S-1 1 k58723s-1.txt FORM S-1 1 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 22, 2000 REGISTRATION NO. 333- -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------ FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ------------------ CMS OIL AND GAS COMPANY (Exact name of Registrant as specified in its charter) ------------------ MICHIGAN 1311 38-1859381 (State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer incorporation or organization) Classification Code Number) Identification No.)

1021 MAIN STREET SUITE 2800 HOUSTON, TEXAS 77002-6606 (713) 651-1700 (Address, including zip code, and telephone number, including area code, of Registrant's principal executive offices) ------------------ WILLIAM H. STEPHENS III ALAN M. WRIGHT EXECUTIVE VICE PRESIDENT, GENERAL COUNSEL SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER AND SECRETARY CMS ENERGY CORPORATION CMS OIL AND GAS COMPANY FAIRLANE PLAZA SOUTH 1021 MAIN STREET SUITE 1100 SUITE 2800 330 TOWN CENTER DRIVE HOUSTON, TEXAS 77002-6606 DEARBORN, MICHIGAN 48126 (713) 651-1700 (313) 436-9560

(Name, address, including zip code, and telephone number, including area code, of agent for service) ------------------ Copies to: MICHAEL D. VAN HEMERT, ESQ. ANDREW H. SHAW, ESQ. S. KINNIE SMITH, ESQ. ASSISTANT GENERAL COUNSEL SIDLEY & AUSTIN SKADDEN, ARPS, SLATE, CMS ENERGY CORPORATION BANK ONE PLAZA MEAGHER & FLOM LLP FAIRLANE PLAZA SOUTH, SUITE 1100 10 SOUTH DEARBORN STREET FOUR TIMES SQUARE 330 TOWN CENTER DRIVE CHICAGO, ILLINOIS 60603 NEW YORK, NEW YORK 10036 DEARBORN, MICHIGAN 48126 (312) 853-7000 (212) 735-3000 (313) 436-9602

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after the effective date of this Registration Statement. IF ANY OF THE SECURITIES BEING REGISTERED ON THIS FORM ARE TO BE OFFERED ON A DELAYED OR CONTINUOUS BASIS PURSUANT TO RULE 415 UNDER THE SECURITIES ACT OF 1933, CHECK THE FOLLOWING BOX. [ ] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ------------ If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ------------ If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] ------------ If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] CALCULATION OF REGISTRATION FEE

(1) Estimated solely for purposes of calculating the registration fee pursuant to Rule 457 of the Securities Act of 1933. (2) Excludes $100,000,000 maximum aggregate initial offering price of common stock previously registered pursuant to a registration statement filed by the registrant on Form S-1 (File No. 33-63693) under which no securities have been issued; the filing fee of $34,483 associated with such securities was previously paid with that registration statement. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. Pursuant to Rule 429 under the Securities Act, this registration statement contains a combined prospectus that also relates to $100,000,000 maximum aggregate initial offering price of common stock previously registered pursuant to a registration statement filed by the registrant (then named CMS NOMECO Oil & Gas Company) on Form S-1 (File No. 33-63693) under which no securities have been issued. The filing fee of $34,483 associated with such securities was previously paid with that registration statement. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IS NOT SOLICITING AN OFFER TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT PERMITTED. SUBJECT TO COMPLETION, DATED NOVEMBER 22, 2000 SHARES [LOGO] CMS OIL AND GAS COMPANY COMMON STOCK ------------------ We are selling shares of common stock and the selling shareholder, CMS Enterprises Company, our parent company, is selling shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling shareholder. The underwriters have an option to purchase a maximum of additional shares from us and/or the selling shareholder to cover over-allotments of shares. Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $ and $ per share. We will apply to list our common stock on The New York Stock Exchange under the symbol "CGS." Concurrently with this offering, we plan to issue $200,000,000 aggregate principal amount of our senior subordinated notes in either the public or private markets. Neither offering is contingent upon the other. Following this offering, CMS Enterprises Company and CMS Energy Corporation, its parent company, will continue to beneficially own approximately % of our common stock and will be able to determine, or have significant influence over, the outcome of all corporate actions requiring shareholder approval. INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 9.

Delivery of our shares of common stock will be made on or about , 2001. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. CREDIT SUISSE FIRST BOSTON The date of this prospectus is , 2001. 3 [Maps illustrating the location of international and domestic oil and gas properties] 4 ------------------------ TABLE OF CONTENTS

------------------ YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS DOCUMENT OR TO WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH INFORMATION THAT IS DIFFERENT. THIS DOCUMENT MAY ONLY BE USED WHERE IT IS LEGAL TO SELL THESE SECURITIES. THE INFORMATION IN THIS DOCUMENT MAY ONLY BE ACCURATE ON THE DATE OF THIS DOCUMENT, AS THIS DOCUMENT MAY BE AMENDED OR SUPPLEMENTED AFTER THAT DATE IN THE EVENT OF ANY SUBSEQUENT MATERIAL CHANGES DURING THE PROSPECTUS DELIVERY PERIOD SPECIFIED BELOW. DEALER PROSPECTUS DELIVERY OBLIGATION UNTIL , 2001 (25 DAYS AFTER THE COMMENCEMENT OF THE OFFERING), ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE DEALER'S OBLIGATION TO DELIVER A PROSPECTUS WHEN ACTING AS AN UNDERWRITER AND WITH RESPECT TO UNSOLD ALLOTMENTS OR SUBSCRIPTIONS. ii 5 PROSPECTUS SUMMARY This summary highlights selected information from this prospectus, but does not contain all information that may be important to you. We encourage you to read this prospectus in its entirety before making an investment decision. CMS Oil and Gas Company is currently a wholly-owned subsidiary of CMS Enterprises Company, which in turn is a wholly-owned subsidiary of CMS Energy Corporation. Unless the context otherwise requires, references to (1) "CMS Oil and Gas," "we," "us" or "our" refers to CMS Oil and Gas Company and its subsidiaries; (2) "CMS Enterprises" refers to CMS Enterprises Company; and (3) "CMS Energy" refers to CMS Energy Corporation and its subsidiaries, other than CMS Oil and Gas. Unless otherwise indicated, this prospectus assumes that the underwriters' over- allotment option is not exercised. The September 30, 2000 estimated reserve data included throughout this prospectus are based on the report of Ryder Scott Company, L.P., independent petroleum engineers. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in "Glossary of Oil and Natural Gas Terms" beginning on page 101. ABOUT CMS OIL AND GAS COMPANY CMS Oil and Gas Company is an independent energy company engaged in oil and natural gas acquisition, exploration and development activities principally in Africa, the U.S. and South America. Formed in 1967, we have grown our operations through acquisition and exploration and are currently one of the larger U.S. based independent oil and natural gas companies. Our strategy is to increase reserves, production, cash flow and earnings by committing our resources to regions with significant growth prospects and properties that allow us to leverage our extensive operating and technical expertise. On a pro forma basis, excluding our Michigan and Ecuador properties which we recently sold, we have grown our production and estimated proved reserves at annualized rates of 12.4% and 25.4%, respectively, from January 1, 1995 through September 30, 2000. We have achieved these impressive growth rates by employing a lower-risk, disciplined international and domestic acquisition, exploration and development strategy. Internationally, we have been active in Africa and South America for over a decade and currently have concessions which have significant production, reserves and, we believe, reserve growth potential. We are actively exploiting our properties in Equatorial Guinea, Colombia, Venezuela and the Republic of Congo (Brazzaville). Domestically, we have built an attractive reserve base and acreage holdings located principally in the Powder River Basin of Wyoming and Montana and the Permian Basin of West Texas. We are actively exploring and developing these domestic properties which have increasing production and, we believe, significant reserve growth potential. We expect to spend approximately $166.0 million in 2001 to further develop our existing reserves and to pursue attractive exploration opportunities. We believe that our regional operating philosophy, acreage and reserve positions and management expertise provide us with significant opportunities for growth. As of September 30, 2000, we had estimated proved reserves of 212.0 million barrels of oil equivalent, or MMBoe, with a net present value (before taxes) of $1,164.7 million. Of these reserves, 92% were classified as proved developed. We operate properties accounting for approximately 91% of these estimated proved reserves, allowing us to better manage expenses, capital allocation and the timing of exploration and development activities. On a pro forma basis, excluding our recently sold Michigan and Ecuador properties and after giving effect to the acquisition in October 1999 of an additional interest in the Bioko Permit offshore Equatorial Guinea, we produced 7.1 MMBoe in 1999 and 6.3 MMBoe for the nine months ended September 30, 2000. 1 6 The following table summarizes by region our estimated proved reserves as of September 30, 2000 and our average daily net production during the three months ended September 30, 2000:

--------------- (1) For purposes of this table, oil and condensate reserves includes 12.2 million barrels, or MMBbls, of international natural gas liquids, or NGLs, and oil and condensate production includes 0.9 thousand barrels, or MBbls, of international NGLs. OUR STRATEGY Our strategy is to increase reserves, production, cash flow and earnings by committing our resources to regions with significant growth potential and properties that allow us to leverage our extensive operating experience and focused technical expertise. We intend to achieve an attractive return on capital while seeking to diversify our geologic, geographic and political risks. We intend to implement our strategy as follows: FOCUS ON PROPERTIES WITH SIGNIFICANT GROWTH POTENTIAL. We focus on known hydrocarbon provinces with significant growth potential. Internationally, we hold properties which we believe have significant growth potential in West Africa, Colombia and Venezuela. Domestically, our activities are concentrated in the high-growth areas of the Powder River Basin in Wyoming and Montana and the Permian Basin in West Texas. TARGET SPECIFIC REGIONS AND LARGE ACREAGE POSITIONS. We believe that ownership of significant working interests in large acreage positions in targeted regions allows us to achieve economies of scale in the utilization of our geologic, engineering, exploration and production expertise. We own at least a 50% working interest in substantially all of our properties. The concentration of our operations permits us to manage a larger asset base with fewer staff, enabling us to add production at relatively low incremental cost. Moreover, we believe that the collective expertise we acquire as we explore and develop hydrocarbon systems containing multiple prospects should improve our drilling success rates while reducing our finding costs and diminishing our overall drilling and operating risk profile. MANAGE COST STRUCTURE, CAPITAL ALLOCATION AND RISK PROFILE BY SERVING AS OPERATOR. We have operations in seven countries on three continents, and we operate all but one of our major projects. Our operated properties accounted for approximately 91% of our estimated proved reserves as of September 30, 2000. As operator, we can better manage production performance and more effectively control costs, the allocation of capital and the timing of exploration and development of our properties. 2 7 EXPAND OUR POSITION IN DOMESTIC NATURAL GAS. We hold 273,813 net acres in the Powder River Basin, which makes us one of the larger holders of coal bed methane acreage in this basin. By year-end 2000, we will have participated in the drilling of 500 wells in this basin. For the three months ended September 30, 2000, our aggregate net production from this basin averaged 4.2 million cubic feet, or MMcf, per day of natural gas. We expect this production to increase as we plan to participate in the drilling of approximately another 510 wells in 2001 and 700 wells in 2002. In the Permian Basin of West Texas, as of September 30, 2000 we held 44,750 net undeveloped acres and we have options on an additional 43,400 net undeveloped acres. Since June 1999 we have spudded 43 wells, of which 34 were producing, eight were in the process of being drilled or completed and one was a salt water disposal well. For the three months ended September 30, 2000 our aggregate net production from the Permian Basin averaged 9.2 MMcf per day of natural gas. We will continue to seek natural gas exploration, development and acquisition opportunities in these and other gas-prone areas of North America, including western Canada, in order to attain a more balanced portfolio and capitalize on the strength of the domestic gas market. LEVERAGE MANAGEMENT AND TECHNICAL EXPERTISE AND EXPERIENCE. We employ seasoned managers and technical personnel who have many years' experience operating in our targeted geographic regions. We have 38 professionals dedicated to our West Africa properties with over 246 cumulative years of area-specific management and technical experience and 26 professionals dedicated to our South American properties with over 140 cumulative years of area-specific management and technical experience. Furthermore, at least in part due to our former Antrim Shale operations in Michigan and other domestic operations, our Powder River Basin and West Texas operations employ dedicated personnel with over 55 cumulative years of domestic experience in the exploitation of tight gas sands and unconventional reservoirs. We believe that our seasoned managers and technical personnel have contributed to a significant reduction in our per-foot drilling costs over the past five years. ACQUISITIONS AND DISPOSITIONS OF PROPERTIES We continually reevaluate our portfolio of property holdings in order to maintain a disciplined adherence to our business strategy. As a result, we have sought to make acquisitions of reserves which complement our business objectives and to divest properties that dilute those objectives. Acquisition of Additional Working Interest in Equatorial Guinea In October 1999, we purchased an additional 11.5% working interest in the Bioko Permit in Equatorial Guinea for approximately $53.3 million in cash, increasing our working interest in this property from 42.5% to 54.0%. Acquisition of Methanol Production Facility We have agreed to purchase, prior to the completion of this offering, a 50% interest in Atlantic Methanol Capital Company, which owns an indirect 90% interest in a 2,500 metric ton per day methanol production facility currently in the late stages of construction on Bioko Island in Equatorial Guinea. We will purchase this interest from CMS Gas Transmission Company, a subsidiary of CMS Enterprises, by issuance of a note in the principal amount of approximately $137.0 million, which will be repaid with a portion of the aggregate proceeds from this offering and our concurrent offering of senior subordinated notes. Atlantic Methanol Capital has issued $125.0 million of limited recourse indebtedness, which is secured by, among other things, a pledge of 60% of the interest we expect to acquire. We believe that ownership of an interest in this methanol facility will allow us to further enhance the value of our natural gas reserves in Equatorial Guinea. Prior to our agreement to acquire this facility, our return on this natural gas was limited by the $0.25 per MMBtu selling price under a 20-year contract to sell up to 126,500 MMBtu per day of natural gas to the facility. Given that natural gas is typically the largest cost component in the production of methanol, we believe this gas sales contract will position this facility to be one of the lowest cost methanol producers in world markets. 3 8 Recent Dispositions of Non-Strategic Assets In the first half of 2000, we sold our Michigan and Ecuador properties for aggregate cash consideration of approximately $258.7 million. We sold these properties because they had lower growth potential than our other properties, our working interest was relatively small and, with respect to Ecuador, we did not serve as operator. OUR RELATIONSHIP WITH CMS ENERGY Pending completion of this offering, we are an indirect wholly-owned subsidiary of CMS Energy Corporation. CMS Enterprises Company owns all of our outstanding stock, and CMS Energy owns all of the outstanding common stock of CMS Enterprises. CMS Energy is a major international energy company with electric and natural gas utility operations; independent power production; natural gas pipelines, gathering, processing and storage; energy marketing, services and trading; and, through us, oil and natural gas exploration and development. After completion of this offering, CMS Energy will continue to own indirectly approximately %, or approximately % if the underwriters exercise their over-allotment option in full, of the outstanding shares of our common stock. OUR EXECUTIVE OFFICES Our principal executive offices are located at 1021 Main Street, Suite 2800, Houston, Texas, 77002, and our telephone number is (713) 651-1700. THE OFFERING Common stock offered by us.......... shares Common stock offered by CMS Enterprises......................... shares Common stock to be outstanding after this offering(1).................... shares Common stock to be held by CMS Enterprises after this offering..... shares Use of proceeds..................... We intend to use the net proceeds to us from this offering, together with the net proceeds from our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes, for repayment of debt under our bank credit facility and repayment of intercompany notes payable to CMS Energy. In the aggregate, CMS Energy will generate funds of approximately $ million from these transactions. Any remaining proceeds will be used for general corporate purposes. Proposed New York Stock Exchange symbol.............................. "CGS" --------------- (1) Excludes (a) shares of common stock issuable upon exercise of options we expect to grant to our executive officers in connection with this offering at an exercise price equal to the initial public offering price and (b) restricted shares of common stock we expect to issue to our outside directors in connection with this offering. 4 9 SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA The following table presents our summary historical and pro forma consolidated financial data as of the dates and for the periods shown. The data presented in these tables are derived from "Selected Historical Consolidated Financial Data," "Unaudited Pro Forma Consolidated Financial Data" and our historical consolidated financial statements and related notes included elsewhere in this prospectus. You should read those sections for a further explanation of the data summarized here. The pro forma income statement and other data for the year ended December 31, 1999 and for the nine months ended September 30, 2000 give effect to the transactions noted below as if these transactions had been completed on January 1 of the relevant period: - our acquisition in October 1999 of an additional 11.5% interest in the Bioko Permit offshore Equatorial Guinea and the disposition of our properties in Michigan and Ecuador in March 2000 and June 2000, respectively; and - the application of the estimated net proceeds to us of $140.3 million from shares sold by us in this offering and of $194.0 million from our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes with an assumed annual interest rate of 9.5%. The pro forma balance sheet data give effect to the transactions noted below as if these transactions had been completed on September 30, 2000: - our proposed distribution of a $39.0 million note payable to our parent, CMS Enterprises; and - our pending acquisition of an indirect 45% interest in a methanol production plant for a note in the principal amount of approximately $137.0 million. The pro forma as adjusted balance sheet data give effect to these two transactions, as well as our sale of shares of common stock in this offering and our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes and the application of the estimated net proceeds to us from these offerings of $140.3 million and $194.0 million, respectively, as if these transactions had been completed on September 30, 2000. The pro forma financial data are not necessarily indicative of the financial position or results of operations that would have been achieved if the pro forma transactions had occurred on the dates indicated or the financial position or results of operations that will be achieved in the future. The consolidated financial position and results of operations as of and for the nine months ended September 30, 2000 are not necessarily indicative of the financial position or results of operations that may be achieved as of and for the full year ending December 31, 2000.

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--------------- (1) Includes additional interest in the Bioko Permit offshore Equatorial Guinea, which we acquired in October 1999. (2) Includes NGLs. The following table summarizes the net present value of future cash flows and the standardized measure of discounted future net cash flows attributable to our estimated proved reserves as of September 30, 2000, discounted at 10% per annum. The net present value of future cash flows has been prepared by Ryder Scott Company using the September 30, 2000 prices of $5.13 per million British thermal units, or MMBtu, of natural gas at the Henry Hub Index and $30.83 per barrel of oil at the Cushing spot market, except where we have fixed and determinable prices or service fees provided by contracts. The standardized measure of discounted future net cash flows has been prepared by us using the net present value information prepared by Ryder Scott.

--------------- (1) Net present value represents the net present value of future cash flows on a pre-tax basis calculated in accordance with SEC guidelines. Net present value is sometimes also known as PV 10. (2) The standardized measure of discounted future net cash flows represents the net present value of future cash flows attributable to our reserves after income tax, calculated in accordance with the provisions of Statement of Financial Accounting Standards No. 69. For further details concerning this calculation, see "Business and Properties -- Reserves." 7 12 SUMMARY OPERATING DATA The following table presents our summary operating data for the periods shown. The pro forma operating data for the year ended December 31, 1999 give effect to the transactions noted below as if these transactions had been completed on January 1, 1999: - our acquisition in October 1999 of an additional 11.5% interest in the Bioko Permit offshore Equatorial Guinea; and - the disposition of our properties in Michigan and Ecuador in March 2000 and June 2000, respectively. The pro forma operating data for the nine months ended September 30, 2000 give effect to the disposition of our properties in Michigan and Ecuador as if these transactions had been completed on January 1, 2000.

--------------- (1) Adjusted to reflect amounts received or paid under contracts entered into to hedge the price of production. 8 13 RISK FACTORS You should carefully consider the following risk factors before deciding to purchase shares of our common stock. We have separated the risks into three categories: - risks relating to our business, properties and industry; - risks relating to our relationship with CMS Energy; and - risks relating to the securities markets and ownership of our common stock. RISKS RELATING TO OUR BUSINESS, PROPERTIES AND INDUSTRY Oil, natural gas and methanol prices fluctuate widely, and low prices could harm our business. Our revenues, operating results and future growth are highly dependent upon the prevailing prices of, and demand for, oil and natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to raise additional capital. Historically, the markets for oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. The prices of oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include: - the level of consumer product demand; - weather conditions; - domestic and foreign governmental regulations and taxes; - the price and availability of alternative fuels; - transportation costs; - political conditions in the Middle East and other petroleum producing areas; - the domestic and foreign supply of oil and natural gas; - the price of foreign imports; and - overall economic conditions. It is impossible to predict future oil and natural gas price movements with any certainty. Declines in oil or natural gas prices could also reduce the amount of oil and natural gas that we can produce economically. Upon our acquisition of CMS Gas Transmission's interest in a methanol production facility and the expected commencement of operations of this plant in the first half of 2001, the price of methanol will also significantly influence our financial condition and results of operations. There is significant volatility in the price of methanol. Our price hedging may result in diminished financial performance or losses. In order to reduce our exposure to the price risks to which we are subject in the sale of our oil and natural gas, we enter into hedging arrangements from time to time. Our hedging arrangements apply to only a portion of our production and provide only limited price protection against fluctuations in the oil and natural gas markets. To the extent that we engage in hedging activities, we may not realize the benefits of price increases for natural gas or oil above the levels of the hedges. If we choose not to engage in hedging arrangements, we may be more adversely affected by changes in natural gas and oil prices than if we did engage in hedging arrangements. 9 14 Hedging arrangements also expose us to risk of financial loss in some circumstances, including: - lower production than expected; or - default by the counterparty to the hedging contract, which may be an affiliate of CMS Energy, on its contractual obligations. For a discussion of our recent hedging activities and the expected adoption of new policies applicable to our hedging, we refer you to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Transactions" and "Business and Properties -- Hedging Objectives," respectively. Reserve estimates are inherently uncertain and depend on many assumptions that may be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated. The reserve data set forth in this prospectus represent only estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable interpretations and assumptions, including: - the interpretation of available technical data; - the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices; - future operating costs; - severance and excise taxes; - development costs; and - workover and remedial costs. Any significant inaccuracies in these interpretations or assumptions could cause the estimated quantities and net present value of reserves shown in this prospectus to be overstated. Please read "Business and Properties -- Reserves" for a discussion of our proved natural gas and oil reserves. We often hold reserves located outside the U.S. pursuant to complex contractual arrangements with foreign governments. Under these arrangements, the relative sharing of benefits between us and the foreign government may vary depending on prices received for production, volume of production or costs. These contractual provisions further complicate estimating reserves and net present value. Moreover, some of the producing wells included in our reserve report, such as those in the Powder River Basin and in West Texas, have produced for a relatively short period of time as of September 30, 2000. Because some of our reserve estimates are not based on lengthy production histories, these estimates are less reliable than estimates based on lengthy production histories. For these reasons, estimates of economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of expected future cash flows prepared by different engineers or by the same engineers at different times may vary substantially, and reserve estimates may be subject to downward or upward adjustments, based upon these factors. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. You should not assume that the net present value of future cash flows referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the net present value of future cash flows from our proved reserves on prices and costs as of the date of the estimate. Estimates included in this prospectus are based in large 10 15 part on prices that are at or near the highest they have been in a decade. Actual future prices and costs may be materially different. Actual future net cash flows also will be affected by factors such as: - the amount and timing of actual production; - supply and demand for oil and natural gas; - curtailments or increases in consumption by oil and natural gas purchasers; - changes in governmental regulations or taxation; and - the operation of contractual provisions under varying prices, production volumes and costs. The timing of both the production and the incurrence of expenses in connection with development and production of oil and natural gas properties will affect the amount and timing of actual future net cash flows and standardized measure data from proved reserves. In addition, the calculation of the net present value of future cash flows using a 10% annual discount rate as required by the SEC is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the oil and natural gas industry in general. Our future oil and natural gas production and, therefore, our future cash flows are dependent upon our success in finding or acquiring additional reserves. In general, the rate of production from oil and natural gas properties declines as reserves are depleted. The rate of decline depends on reservoir characteristics and other factors. Unless we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our estimated proved reserves will decline as we produce those reserves. Our future oil and natural gas production and, therefore, our future cash flows and income are highly dependent upon our degree of success in finding or acquiring additional reserves. Our acquisition, exploration and development activities require substantial amounts of capital, and we may be unable to obtain needed financing on satisfactory terms. Our future oil and natural gas exploration, development and acquisition activities are highly dependent upon our ability to obtain funds for these activities. The business of acquiring, exploring for and developing reserves is capital intensive. We intend to finance our capital expenditures with cash flow from operations and financing arrangements expected to be in place as of the date of completion of this offering. Additional financing sources may be required in the future. Financing may not continue to be available under existing or new financing arrangements and we may not be able to obtain necessary financing on acceptable terms, if at all. In particular, our credit facility as we expect it to be in place as of the completion of this offering will likely impose limitations on our ability to borrow under the facility which relate to the value of our asset base as determined by market prices of oil and natural gas. Our international properties, which are a very significant part of our assets, are included in our asset base at reduced values for this purpose. If we experience a reduction in cash flow from operations or cannot freely access external sources of capital, we may have to curtail our acquisition, drilling or other plans or sell some assets on an unfavorable basis. Exploration, development and production operations are high-risk activities. Our oil and natural gas operations are subject to the economic risks typically associated with exploration, development, production and marketing activities, including significant expenditures required to locate and acquire producing properties and to drill exploratory, appraisal and development wells. In conducting exploration and development activities, we may drill unsuccessful wells and experience investment losses. We may not be able to produce economically or market satisfactorily discovered oil or natural gas. Moreover, the presence of unanticipated pressure or irregularities in formations or accidents may cause our exploration, development and production activities to be unsuccessful and could result in a 11 16 total loss of our investment in affected properties. Our operations may be materially curtailed as a result of a number of factors, including: - lack of infrastructure; - bad weather; - land title problems; - failure to obtain, or changes in, necessary governmental or regulatory permits or approvals; and - labor or other shortages. In addition, some of our producing properties are subject to production limitations imposed by governmental or regulatory authorities or under contracts. Consequently, our actual future production may be substantially affected by factors beyond our control, any of which could have a material adverse effect on our financial results. Our drilling success will depend, in part, on our ability to attract and retain experienced geologists, geophysicists, engineers and other professional personnel. Competition for such experienced professional personnel is extremely intense. If we cannot retain our current personnel or attract additional experienced personnel, our ability to successfully pursue exploration, development and production activities could be adversely affected. Our ability to market our oil and natural gas may be impaired by capacity constraints on the gathering systems and pipelines that transport our oil and natural gas. A substantial portion of our oil and most of our natural gas are transported through gathering systems and pipelines which we do not own. Transportation capacity on gathering systems and pipelines is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other oil or natural gas shippers that may have priority transportation agreements. Aggregate methane gas production from the Powder River Basin in Wyoming and Montana is likely to increase significantly over the next few years. We believe that, commencing sometime in 2001, production may exceed the existing interstate gas transportation capacity. A pipeline expansion and a new pipeline have been proposed, although we cannot assure you that either will be built or built soon enough to avoid capacity constraints. We may have to curtail production, pay significantly higher transportation costs or receive a lower price for at least a portion of our Powder River Basin production if pipeline transportation capacity increases do not keep pace with increased overall production in this region. If transportation capacity is materially restricted or is unavailable in the future, our ability to market our oil or natural gas could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition or results of operation. We could be liable under tax indemnities relating to potential recapture of dual consolidated losses. We could take various actions in the future which would require our affiliated group or an unrelated affiliated group of corporations to recapture or include in income an amount equal to certain losses, referred to as dual consolidated losses, that may have been used previously to offset taxable income for U.S. federal income tax purposes. These actions generally are within our control and we do not intend to take them. Nonetheless, if we did, we could be liable directly or under tax indemnity agreements for substantial U.S. federal income taxes that could total in excess of $71.0 million plus interest. We could also be liable for this amount if, in contrast to our expectation, we and CMS Energy fail to obtain a closing agreement from the Internal Revenue Service in connection with this offering and if, contrary to its contractual obligations, CMS Energy fails to pay the taxes and interest that result. We could also be liable for an amount currently estimated to be in excess of $44.5 million plus interest if, contrary to our expectations, a party unrelated to us fails to fulfill its obligations under indemnity agreements relating to dual consolidated losses associated with assets held by the unrelated party. Finally, we could be liable for an amount currently estimated to be in excess of $11.5 million plus interest if, again contrary to our 12 17 expectations, a party unrelated to us fails to fulfill its obligations under indemnity agreements relating to dual consolidated losses and other parties fail in their indemnity obligations to us. We could incur high effective combined rates of tax on future foreign earnings generated by our domestic affiliates and substantial additional taxes upon repatriation of earnings from our foreign affiliates. U.S. corporations generally are entitled to a foreign tax credit that reduces the U.S. federal income tax burden on foreign earnings generated directly or by domestic affiliates and on the repatriation of earnings from foreign subsidiaries. However, this credit is subject to various limitations, including limitations arising from the prior use of foreign losses to offset domestic income. Some of these limitations are applicable to us and may substantially increase the U.S. federal income tax burden on the future foreign earnings of our domestic affiliates and on earnings repatriated from our foreign affiliates. We could be required to record a U.S. income tax provision as to prior years' earnings from foreign affiliates. Although we have no current plans to do so, if we change our policy and decide against indefinitely reinvesting our unrepatriated foreign earnings offshore, we may be required for financial accounting purposes to record additional deferred taxes with respect to all of our prior years' unrepatriated foreign earnings. It is estimated that, if we were required to do so as of September 30, 2000, the additional deferred taxes could be approximately $32.0 million. Our international operations may be subject to political and economic uncertainties and other risks beyond our control. Almost 90% of our estimated proved reserves, as well as the methanol production facility in which we have agreed to acquire an interest, are located outside the U.S. Our international oil and natural gas exploration, development and production activities and our methanol production business are subject to: - political and economic uncertainties, including changes in energy policies or the personnel administering them; - expropriation of property; - cancellation or modification of contract rights; - difficulty enforcing contract rights, either within or outside of the jurisdiction in which we have assets; - foreign exchange restrictions; - currency fluctuations; - royalty and tax increases; and - other risks arising out of foreign governmental sovereignty over the areas in which our operations are conducted. Additional risks include loss due to civil strife, acts of war, guerrilla activities, insurrection, border disputes and leadership succession turmoil. These risks may be higher in the developing countries in which we conduct our exploration, development and production activities and our methanol production business. We generally do not fully insure against these risks. Consequently, our international exploration, development and production activities and our methanol production business may be substantially affected by factors beyond our control, any of which could have a material adverse effect on our financial condition or results of operations. Furthermore, in the event of a dispute arising from our international operations, we may be subject to the exclusive jurisdiction of courts outside the U.S. or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S., which could adversely affect the outcome of such a dispute. 13 18 In late 1995, the Hydrocarbons Ministry of the government of the Republic of Congo (Brazzaville) notified us as operator of the Marine I Exploration Permit offshore Congo, which includes the Yombo Field, that it would like to convert the concession governing the participants' interests in this project to a production sharing contract. The Congolese government has significant leverage to request changes due to its broad governmental and regulatory powers. Discussions with the Congolese government concerning its request began in March 1996 but were subsequently suspended. The discussions recently resumed and will likely continue into 2001. Although the Congolese government has indicated that it desires to achieve economic parity in effecting the contract conversion, we cannot currently predict what impact, if any, these discussions will have on the project's economics, and we cannot assure you that these discussions or their outcome will not have a material adverse effect on our estimated reserves or financial results. There are uncertainties associated with conducting our businesses in the Republic of Equatorial Guinea. The Alba Field within the Bioko Permit, which represents 70.1% of our estimated proved reserves, and the methanol production plant in which we have agreed to acquire an interest are both located in the territory of the Republic of Equatorial Guinea in West Africa. As with many emerging markets, there are uncertainties associated with conducting business in this Republic, including expropriation, renegotiation or nullification of existing contracts, that could affect the ownership of and operation of our assets there. The U.S. Government and the United Nations have raised concerns regarding human rights issues in the Republic, and the International Monetary Fund has raised concerns regarding financial transparency issues in the Republic. We understand that these organizations are currently working with the government of Equatorial Guinea to address these issues. We face various operating hazards typical of the oil and natural gas business, some of which are not insurable. The oil and natural gas business involves various operating hazards such as: - well blowouts; - cratering; - explosions; - uncontrollable flows of underground natural gas, oil or formulation water; - fires; - formation with abnormal pressures; - pollution; - releases of toxic gas; and - other environmental hazards and risks. We could experience substantial losses from any of these hazards. Our offshore operations also are subject to the additional hazards of marine operations, such as severe weather, capsizing and collision. In addition, we may be legally responsible for environmental damages caused by previous owners of property which we have purchased or leased. As a result, we may incur substantial liabilities to third parties or governmental entities. The insurance we maintain may not cover all of these risks and losses. The occurrence of such an event not fully covered by insurance could have a material adverse effect on our financial condition or results of operations. The methanol plant in which we have agreed to acquire an indirect interest has construction and operating risks and no operating history. Completion of construction of the methanol plant in which we have agreed to acquire an indirect interest is currently scheduled for May 2001. However, completion of construction could be delayed or otherwise adversely affected by factors such as shortages of material and labor, work stoppages, labor 14 19 disputes, weather interferences, unforeseen engineering or environmental problems, unanticipated cost overruns or other similar events which are beyond our reasonable control. Operation of the methanol plant will involve many risks that are typical in the manufacturing of a chemical product. These risks include: - the breakdown or failure of equipment or processes; - the performance of the plant below expected levels of output or efficiency; - difficulties or delays in obtaining spare parts or equipment; - interruptions in the supply of natural gas; - the costs of shipping and handling methanol; - labor disputes and strikes; - industrial accidents; - catastrophic events such as fires, tornadoes, typhoons, earthquakes, floods or other similar events; - changes in economic conditions; and - changes in laws, such as environmental laws, tax laws or permit requirements. The occurrence of these or other events could significantly reduce or eliminate revenues generated by sales of natural gas to the plant or by operation of the plant and significantly increase the plant's operating and maintenance expenses. The methanol plant has no operating history upon which to evaluate its performance. The performance of the plant will depend on its management's ability to address the risks encountered by development-stage companies and to implement the business plan of the joint venture which owns the plant. The methanol plant may not be successful in implementing the business plan, and if it is not, its as well as our financial position and results of operations could be adversely affected. Even if the joint venture is successful in implementing its business plan, the financial position or results of operations of the methanol plant may not meet expectations. The notes issued by Atlantic Methanol Capital, in which we have agreed to acquire an interest, may be accelerated by events outside of our control, and if that happens we could be required to fund the repayment of these notes or lose up to 60% of our interest in the methanol production plant. Under the indenture relating to the notes of Atlantic Methanol Capital issued to finance a portion of CMS Gas Transmission's investment in the methanol production plant, if these notes are not repaid, the occurrence of various trigger events, many of which are related to the stock price and credit quality of CMS Energy, will allow the indenture trustee to exercise its remedies with respect to the security for the notes. These remedies include foreclosure on 60% of our interest in the methanol facility, which has been pledged to secure the notes. In addition, we have agreed to indemnify CMS Energy for any costs or expenses incurred by it in connection with the repayment of the principal of or interest on these notes. Our operations are subject to extensive governmental regulation, which may adversely affect our ability to conduct our business or increase our costs. Our operations are subject to regulation at the federal, state and local levels in the U.S. and by other countries in which we conduct business, including regulation relating to matters such as the exploration for and the development, production, marketing, pricing, transmission and storage of oil and natural gas, as well as environmental and safety matters. Failure to comply with these regulations could result in substantial liabilities to third parties or governmental entities, the payment of which could have a material adverse effect on our financial condition or results of operations. Moreover, laws or regulations enacted in the future or the modification of existing laws or regulations could adversely affect our exploration for or development, production or marketing of oil or natural gas or our production of methanol. 15 20 Our operations are subject to significant environmental laws and regulations, which may adversely affect our ability to conduct our business or increase our costs. Extensive federal, state and local laws and regulations relating to health and environmental quality in the U.S., as well as environmental laws and regulations of other countries in which we operate, affect nearly all of our operations. These laws and regulations set various standards regulating various aspects of health and environmental quality, provide for penalties and other liabilities for the violation of these standards and in some circumstances establish obligations to remediate current and former facilities and off-site locations. We could incur significant liability for damages, clean-up costs and/or penalties in the event of discharges into the environment, environmental damage caused by us or previous owners of our property or non-compliance with environmental laws or regulations. This liability may include response costs under the Comprehensive Environmental Response, Compensation and Liability Act or state counterparts. In addition to actions brought by governmental agencies, we could face actions brought by private parties or citizens groups. This liability could have a material adverse effect on our financial results. Moreover, we cannot predict what environmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be administered, enforced or made more stringent. Our Powder River Basin coal bed methane drilling results in the discharge of large volumes of water into adjacent lands and waterways. While current activities are done under permits, the environmental soundness of this practice is coming under increased scrutiny. Moratoriums on issuance of additional permits, or more costly methods of handling these produced waters, may affect future well development. Compliance with more stringent laws or regulations, or more vigorous enforcement policies of the regulatory agencies, or difficulties in negotiating required surface use agreements with land owners, could delay our Powder River Basin drilling program and/or require us to make material expenditures for the installation and operation of systems and equipment for remedial measures, all of which could have a material adverse effect on our financial condition or results of operations. About one-third of our acreage in the Powder River Basin is U.S. federal land and therefore subject to the environmental impact statement, or EIS, process under the National Environmental Policy Act. In addition, Montana has its own EIS process applicable to non-federal lands. The EIS for the Wyoming portion of the Powder River Basin federal lands was completed in the fall of 1999, but is in the process of being supplemented to support a substantially larger number of wells. The Montana EIS process, which is being coordinated between the federal Bureau of Land Management and Montana authorities, is just getting under way. The EIS process, once completed, may not support all potential coal bed methane production well prospects. Moreover, public opposition to new drilling may cause relevant state or federal authorities to impose production limits or other permit restrictions. For example, an environmental organization recently challenged the ongoing permitting of coal bed methane wells in Montana without completion of any site-specific or programmatic environmental impact statement. We do not believe additional environmental assessments are required under applicable legal requirements, and we have moved to intervene in the lawsuit. However, in the event that additional studies are required, this litigation could negatively impact our planned future development activity in Montana. Any delays, limitations or denials with respect to environmental or other approvals necessary for us to develop our acreage in the Powder River Basin could adversely affect our financial condition or results of operations. In March 1999, the State of California ordered the phase-out of MTBE (methyl tertiary-butyl ether) from reformulated gasoline by the end of 2002 in accordance with an Executive Order of the Governor. MTBE, for which methanol is an ingredient, is an oxygenate and octane enhancer for gasoline. The phase-out is the result of concerns that MTBE may contaminate drinking water supplies due to gasoline leaking from underground storage tanks. California's legislative initiative and potentially similar legislative initiatives in other states or at the federal level could materially reduce demand for MTBE throughout the U.S. and elsewhere. Reduced demand for methanol resulting from reduced demand for MTBE could adversely affect our financial position or results of operations. 16 21 We face significant competition in all areas of our business. The oil and natural gas industry is highly competitive. We face competition in all aspects of our business, including: - acquiring reserves, leases, licenses and concessions; - obtaining the equipment and labor needed to conduct our operations; and - marketing our oil and natural gas. Our competitors include multinational energy companies, government-owned oil and natural gas companies, other independent oil and natural gas concerns and individual producers and operators. Because both oil and natural gas are fungible commodities, the principal form of competition with respect to product sales is price competition. Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of our larger competitors may be better able to respond to factors such as changes in worldwide oil or natural gas prices or levels of production, the cost and availability of alternative fuels or the application of government regulations, which affect demand for our oil and natural gas production and which are beyond our control. Moreover, many competitors have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. We expect this high degree of competition to continue. The methanol business in which we intend to engage through our acquisition of an interest in Atlantic Methanol Capital is also highly competitive. Many of the competitors are larger and have greater financial resources than the methanol facility. These competitors of the methanol facility of Atlantic Methanol Capital also may operate multiple plants, offsetting some risks to which a single-plant producer such as the methanol facility may be subject. Methanol consumers, additionally, may prefer the security of purchasing from a multiple-plant producer. As a result, any level of demand established for the methanol facility's product may not be maintained. In addition, the methanol facility's business is based upon widely available technology. Accordingly, barriers to entry, apart from capital availability, may be low, and the entrance of new competitors into the industry may reduce the methanol facility's ability to capture improving profit margins in circumstances where overcapacity in the industry is diminishing. Developments such as these could have a negative impact on the methanol facility's, and our, financial position or results of operations. Recent increases in the prices of oil and natural gas may make it more difficult and costly for us to grow. Our industry is currently experiencing a rapid and significant increase in exploration, development, acquisition and production activity as a result of recent increases in the prices of oil and natural gas. As competition in the industry for labor, materials, including drilling rigs, services and acreage intensifies, we may be forced to implement our plans at a substantially increased cost or to postpone or forego expansion of our operations. We cannot be certain that we will be able to implement our plans on a timely basis or at a cost that is acceptable to us. Acquisition prospects may be difficult to assess and may pose additional risks to our operations. After this offering, we expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to increase our domestic natural gas reserves. The successful acquisition of producing properties requires an assessment of: - recoverable reserves; - exploration potential; - future oil and natural gas prices; - operating costs; 17 22 - potential environmental and other liabilities and other factors; and - permitting and other environmental authorizations required for our operations. In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose numerous additional risks to our operations and financial results, including: - problems integrating the purchased operations, personnel or technologies; - unanticipated costs; - diversion of resources and management attention from our core business; - entry into regions or markets in which we have limited or no prior experience; and - potential loss of key employees, particularly those of the acquired organization. RISKS RELATING TO OUR RELATIONSHIP WITH CMS ENERGY Upon completion of this offering, CMS Energy will have significant influence over our affairs, and our other shareholders will have little or no ability to affect the outcome of shareholder voting during this time. Upon completion of this offering, CMS Enterprises will own approximately %, or approximately % if the underwriters exercise their over-allotment option in full, of our outstanding common stock. As a result, unless CMS Enterprises sells additional shares, CMS Enterprises and its parent company, CMS Energy, will be able to elect, or have a significant influence over the election of, all members of our board of directors and to have significant influence over all matters submitted to a vote of our shareholders. CMS Enterprises and CMS Energy will have significant influence over certain decisions with respect to: - the composition of our board of directors and, through it, any determination with respect to our business direction and policies, including the appointment and removal of officers; - approval of our exploration, development, capital, operating and acquisition expenditure plans; - any determination with respect to mergers or other business combinations; - the acquisition or disposition of assets or businesses by us; - our debt or equity financing, including future issuances of our common stock or other securities; - our capital structure and the amount and timing of any dividend payments; and - amendments to our Restated Articles of Incorporation and Restated Bylaws. This concentration of ownership of our common stock may have an adverse effect on the market price of the common stock. Potential conflicts may arise between us and CMS Energy and its other affiliates that may not be resolved in our favor. The relationship between us and CMS Energy and its other affiliates may give rise to conflicts of interest with respect to, among other things, transactions and agreements among us and CMS Energy and its other affiliates, issuances of additional shares of voting securities, the election of directors or the payment of dividends, if any, by us. When the interests of CMS Energy and its other affiliates diverge 18 23 from our interests, CMS Energy may exercise its influence in favor of its own interests or the interests of another of its affiliates over our interests. Moreover, after completion of this offering and the election of three independent directors, our board of directors will consist of seven members, including one of our officers and three directors and/or officers of CMS Energy or CMS Enterprises. As the individuals affiliated with CMS Energy perform their duties to CMS Energy and to us, conflicts of interest and conflicting demands on the amount of time these individuals will have available for our affairs may arise. These conflicts may not be resolved in our favor. Our intercompany agreements with CMS Energy and its other affiliates are not the result of arm's-length negotiations with third parties. We have entered or will enter into various agreements with CMS Energy and some of its other affiliates which govern various transactions between us and our ongoing relationship following completion of this offering, including agreements relating to: - management and other services; - registration rights; - tax separation; - tax indemnities; - transfer to us of CMS Gas Transmission's interest in Atlantic Methanol Capital and related companies; - provision of administrative support and brokerage services relating to our hedging program; - oil marketing; - gas sales; - gathering and field services; and - conflicts of interest. All of these agreements were or will be entered into in the context of a parent-subsidiary relationship and were negotiated in the overall context of this offering. These agreements may have terms and conditions that may be less favorable to us than agreements that we might have negotiated at arm's-length with independent parties. The prices charged by or to us pursuant to those agreements under which we will provide a product or service to, or receive a product or service from, CMS Energy may be different from the prices that we might be able to receive from, or the prices that we may be required to pay to, third parties for similar products or services. We and CMS Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future. A substantial portion of the proceeds from this offering inure to the benefit of CMS Energy. A substantial portion of the net proceeds from this offering will be paid to CMS Enterprises as the selling shareholder. In addition, a substantial portion of the net proceeds payable to us from this offering, together with the estimated net proceeds from our concurrent offering of $200.0 million aggregate principal amount of senior subordinated notes, will be used to repay intercompany notes payable to CMS Energy. RISKS RELATING TO THE SECURITIES MARKETS AND OWNERSHIP OF OUR COMMON STOCK We will not pay dividends in the foreseeable future. Except for our proposed distribution in December 2000 of a note payable to our parent, CMS Enterprises, in the principal amount of $39.0 million, we have not paid cash dividends or made any other distributions on our common stock since 1989 and have no current plans to pay cash dividends on our common stock in the foreseeable future. We currently intend to retain our cash for the continued expansion of our business, including exploration, development and acquisition activities. In addition, our credit facility as we expect it to be in place as of the completion of this offering, as well as our senior 19 24 subordinated notes, will likely contain customary financial and other covenants that could have the effect of limiting our ability to pay dividends. There is no prior market for our common stock, and our stock price may be volatile. Prior to this offering, there has been no public market for shares of our common stock. Although we have applied to list our common stock on The New York Stock Exchange, we cannot assure you that an active public market for our common stock will develop or be sustained. Furthermore, the market price for our common stock could decline below the public offering price set forth on the cover page of this prospectus. We and the representative of the underwriters will determine the initial public offering price based on the factors described under "Underwriting." This determination may not necessarily equal the intrinsic value, or fix the market value, of our common stock. The trading prices of our common stock could be subject to significant fluctuations in response to variations in results of operations and other factors. The sale of shares of our common stock eligible for future sale may adversely affect the price of our common stock. Sales of substantial amounts of our common stock in the public market following this offering could adversely affect the market price of the common stock. We, CMS Enterprises, CMS Energy and each of our directors and executive officers have agreed, for a period of days after the date of this prospectus, not to offer, pledge, sell, contract to sell or otherwise dispose of any shares of our common stock or other securities convertible or exchangeable into our common stock (other than pursuant to employee stock incentive plans existing or contemplated on the date of this prospectus and for other specified purposes), without the prior written consent of Credit Suisse First Boston Corporation. Upon expiration of this period, all shares of our common stock held by CMS Enterprises will be eligible for sale in the public market, subject to compliance with the volume and other limitations of Rule 144 under the Securities Act of 1933, as amended. In addition, we intend to enter into a registration rights agreement with CMS Enterprises pursuant to which CMS Enterprises at any time may cause us to register under the Securities Act all or any part of its shares of our common stock for sale into a public market or otherwise. The sale of shares upon the expiration of this period, or the perception of the availability of shares for sale, could adversely affect the prevailing market price of our common stock. Provisions in our organizational documents and state law could prevent or delay a change of control of our company that a shareholder may consider favorable. Various provisions of our Restated Articles of Incorporation, Restated Bylaws and change of control severance agreements which we have entered into with some of our executive officers could delay, defer or prevent a change of control of our company without further action by our shareholders, could discourage potential investors from bidding for our common stock at a premium over the market price of the common stock and could adversely affect the market price of, and the voting and other rights of the holders of, the common stock. In addition, the Michigan Business Corporation Act contains some provisions which, among other things, restrict the ability of shareholders to cause a merger or business combination with or obtain control of us. These provisions may be considered disadvantageous by a shareholder. 20 25 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Some of the information in this prospectus contains forward-looking statements. Forward-looking statements give our current expectations or forecasts of future events and are based on our management's beliefs, as well as assumptions made by and information currently available to them. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include the words "anticipate," "believe," "budget," "estimate," "expect," "intend," "objective," "plan," "possible," "potential," "project" and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. Any or all of our forward-looking statements in this prospectus may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many of these factors, including the risks outlined under "Risk Factors," will be important in determining our actual future results, which may differ materially from those contemplated in any forward-looking statements. These factors include, among others, the following: - oil, natural gas and methanol price volatility; - uncertainties in the estimates of proved reserves and in the projection of future rates of production and timing of development expenditures; - our ability to find and acquire additional reserves; - risks associated with acquisitions, exploration, development and production; - operating hazards attendant to the oil and natural gas business; - potential constraints on our ability to market reserves due to limited transportation space; - risks associated with the financing, construction and operation of the methanol plant in which we expect to acquire an interest; - climatic conditions; - availability and cost of labor, material, equipment and capital; - ability to employ and retain key managerial and technical personnel; - international, national, regional or local political and economic uncertainties, including changes in energy policies, foreign exchange restrictions and currency fluctuations; - adverse regulatory or legal decisions, including those under environmental laws and regulations; - the strength and financial resources of our competitors; and - general economic conditions. When you consider these forward-looking statements, you should keep in mind these risk factors and other cautionary statements in this prospectus. Our forward-looking statements speak only as of the date made. 21 26 USE OF PROCEEDS We estimate that the net proceeds to us from our sale of shares of common stock will be approximately $140.3 million ($ million if the underwriters exercise their over-allotment option in full), assuming an initial public offering price of $ per share and after deducting underwriting discounts and commissions and the portion of estimated offering expenses payable by us. We further estimate that the net proceeds from our concurrent offering of $200.0 million aggregate principal amount of senior subordinated notes will be approximately $194.0 million, after deducting transaction expenses and issuance discount. We intend to use our net proceeds from this offering, together with our net proceeds from our concurrent offering of senior subordinated notes, for repayment of the outstanding balance under our credit facility and repayment of three intercompany notes payable to CMS Energy or its affiliates, with any remaining net proceeds to be used for general corporate purposes. As of September 30, 2000, the amount of debt outstanding under our credit agreement was $65.0 million and the amount due under one currently outstanding intercompany note payable to CMS Energy was $62.2 million. Prior to the completion of this offering, we expect to issue two additional intercompany notes in the respective amounts of $39.0 million and approximately $137.0 million. For a description of these notes, as well as our currently outstanding note payable to CMS Energy, please see "Relationship and Certain Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Acquisition of Methanol Plant," "-- Contractual Arrangements -- Note Payable to CMS Enterprises" and "-- Certain Transactions -- CMS Notes." Following application of the net proceeds of these offerings, we anticipate that the total amount of our outstanding debt will be $203.3 million, consisting of $200.0 million of our senior subordinated notes and $3.3 million of capitalized lease obligations. Our current credit facility terminates on May 26, 2002 and the entire unpaid principal balance and accrued interest are due and payable on that date. At September 30, 2000, the average interest rate on borrowings under our credit facility was approximately 7.63% per annum. Substantially all of the borrowings under our credit facility were used for working capital and general corporate purposes. We will not receive any of the proceeds from the sale of common stock offered by the selling shareholder. In the aggregate, CMS Energy will generate funds of approximately $ million from these transactions, derived from a combination of selling its shares of our common stock ($ million) and the repayment of loans from CMS Energy to us (aggregating approximately $238.2 million). DIVIDEND POLICY Except for our proposed distribution in December 2000 of a note payable to our parent, CMS Enterprises, in the principal amount of $39.0 million, we have not declared or paid any cash dividends or made any other distributions on our common stock since 1989, and we have no current plans to declare or pay cash dividends on our common stock in the foreseeable future. We currently intend to retain our future earnings and other cash resources for the continued expansion of our business, including exploration, development and acquisition activities. The payment and amount of any future cash dividends will be at the discretion of our board of directors and will depend upon our future earnings, results of operations, capital requirements, financial condition and other factors as our board of directors deems relevant. In addition, our credit facility as we expect it to be in place upon completion of this offering and the indenture governing our concurrent offering of senior subordinated notes will likely contain customary financial and other covenants that could have the effect of limiting our ability to pay dividends. 22 27 DILUTION Our net tangible book value as of September 30, 2000 was approximately $404.0 million, or $ per share of common stock. Net tangible book value per share as of any date represents the amount of total tangible assets less total liabilities as of that date, divided by the number of shares of common stock then outstanding. Without taking into account any changes in the net tangible book value after September 30, 2000, other than to give effect to our sale of the shares of common stock offered hereby and our receipt of the estimated net proceeds therefrom, our adjusted net tangible book value as of September 30, 2000 would have been approximately $ million, or $ per share of common stock. This represents an immediate increase in net tangible book value of $ per share to our existing shareholder and an immediate dilution of $ per share to investors in this offering. The following table illustrates this dilution:

The following table summarizes, on an adjusted basis as of September 30, 2000, the differences between CMS Enterprises and investors in this offering with respect to the number of shares of common stock purchased from us, the total consideration paid and the average price per share paid, based on an assumed initial public offering price of $ per share and before deducting the underwriting discounts and commissions and the portion of estimated offering expenses payable by us.

These tables do not include shares of common stock reserved for issuance under our stock option plan, under which we expect to grant options to purchase shares of common stock to our executive officers and other key employees upon completion of this offering at an exercise price equal to the initial public offering price. 23 28 CAPITALIZATION The following table sets forth our capitalization as of September 30, 2000. Our capitalization is presented: - on an actual basis; - on a pro forma basis to give effect to: - our proposed distribution in December 2000 of a $39.0 million note payable to our parent, CMS Enterprises; and - our proposed acquisition of an indirect 45% interest in a methanol production plant for a note in the principal amount of approximately $137.0 million; and - on a pro forma as adjusted basis to give effect to: - our sale of shares of common stock in this offering at an assumed initial public offering price of $ per share; - our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes; and - the application of the estimated net proceeds of $140.3 million and $194.0 million, respectively, from this offering and our concurrent offering of senior subordinated notes. You should read this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical consolidated financial statements and unaudited pro forma consolidated financial statements and the related notes included elsewhere in this prospectus.

--------------- (1) "Other" debt consists of capitalized lease obligations in Equatorial Guinea. (2) Excludes shares of our common stock issuable upon exercise of options we expect to grant in connection with this offering and restricted shares of common stock we expect to issue to our outside directors in connection with this offering. 24 29 SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA The following table presents our selected historical consolidated financial data as of the dates and for the periods indicated. The historical consolidated financial data as of and for each of the five years in the period ended December 31, 1999 are derived from our consolidated financial statements which have been audited by Arthur Andersen LLP, independent public accountants. The historical consolidated financial data as of and for the nine months ended September 30, 1999 and 2000 are derived from our unaudited consolidated financial statements which, in the opinion of management, contain all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation thereof. You should read the following data in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our historical consolidated financial statements and unaudited pro forma consolidated financial statements and related notes included elsewhere in this prospectus. The results for the nine months ended September 30, 2000 are not necessarily indicative of the results that may be achieved for the full year ending December 31, 2000.

25 30

--------------- (1) Total operating revenues include the effect of settlement of various hedging transactions to which we have been a party. Excluding the impact of these hedging transactions, total operating revenues for the years ended December 31, 1995, 1996, 1997, 1998 and 1999 would have been $113.8 million, $161.7 million, $175.4 million, $124.4 million and $163.8 million, respectively. Excluding the impact of hedging transactions, total operating revenues for the nine months ended September 30, 1999 and 2000 would have been $108.5 million and $162.3 million, respectively. (2) EBITDAX is earnings before interest, income taxes, depreciation, depletion and amortization, other income (expense), extraordinary item and exploration costs. EBITDAX is presented to provide additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital. EBITDAX should not be considered as an alternative to net income as an indicator of operating performance or as an alternative to cash flow as a measure of liquidity. (3) Costs incurred for exploration, development and acquisition activities, including such of those costs as are expensed under the successful efforts method of accounting. (4) Includes non-cash capital expenditures of $81.4 million relating to two acquisitions completed in 1995. (5) Excludes current maturities of long-term debt. 26 31 UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA The following tables present our unaudited pro forma consolidated financial data as of the dates and for the periods indicated. The pro forma income statement and other data for the year ended December 31, 1999 and for the nine months ended September 30, 2000 give effect to the transactions noted below as if these transactions had been completed on January 1 of the relevant period: - our acquisition in October 1999 of an additional 11.5% interest in the Bioko Permit offshore Equatorial Guinea and the disposition of our properties in Michigan and Ecuador in March 2000 and June 2000, respectively; and - the application of the estimated net proceeds to us of $140.3 million from shares sold by us in this offering and of $194.0 million from our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes with an assumed annual interest rate of 9.5%. The pro forma balance sheet data give effect to the transactions noted below as if these transactions had been completed on September 30, 2000: - our proposed distribution of a $39.0 million note payable to our parent, CMS Enterprises; and - our pending acquisition of an indirect 45% interest in a methanol production plant for a note in the principal amount of approximately $137.0 million. The pro forma as adjusted balance sheet data give effect to these two transactions, as well as our sale of shares of common stock in this offering and our concurrent offering of $200.0 million aggregate principal amount of our senior subordinated notes and the application of the estimated net proceeds to us of $140.3 million and $194.0 million, respectively, from these offerings, as if these transactions had been completed on September 30, 2000. You should read the following data together with our historical consolidated financial statements and related notes included elsewhere in this prospectus. Our pro forma consolidated financial data are not necessarily indicative of the financial position or results of operations that would have been achieved if the pro forma transactions had occurred on the dates indicated or the financial position or results of operations that will be achieved in the future. The consolidated financial position and results of operations as of and for the nine months ended September 30, 2000 are not necessarily indicative of the financial position or results of operations that may be achieved as of and for the full year ending December 31, 2000. 27 32 UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1999

The accompanying notes are an integral part of these statements. 28 33 UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000

The accompanying notes are an integral part of these statements. 29 34 UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30, 2000

The accompanying notes are an integral part of these statements. 30 35 NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS (1) Represents the additional 11.5% interest acquired in the Bioko Permit offshore Equatorial Guinea. (2) Reflects actual revenues (net of hedging), direct operating expenses, direct general and administrative expenses (net of Council of Petroleum Accountants Societies (COPAS) reimbursements) and depletion and depreciation associated with the Michigan and Ecuador properties that were sold. (3) Reflects the pretax gain on the sale of the Michigan and Ecuador properties and interest income earned on unrepatriated cash proceeds from the sale of the Ecuador properties, which is invested in an interest bearing note with an affiliate.

(4) Reflects the interest expense for the assumed cost of increased borrowing on our credit facility for the acquisition of the additional 11.5% interest acquired in the Bioko Permit offshore Equatorial Guinea. (5) Reflects the reduction of interest expense for the assumed pay down on our credit facility.

(6) Represents the pro forma adjustment for the income taxes, at our effective income tax rate (including Section 29 tax credits) in the applicable taxing jurisdiction. (7) EBITDAX is earnings before interest, income taxes, depreciation, depletion and amortization, other income (expense), extraordinary item and exploration costs. EBITDAX is presented to provide additional information about our ability to meet our future requirements for debt service, capital expenditures and working capital. EBITDAX should not be considered as an alternative to net income as an indicator of operating performance or as an alternative to cash flow as a measure of liquidity. (8) Costs incurred for exploration, development and acquisition activities, including such of those costs as are expensed under the successful efforts method of accounting. 31 36 (9) Reflects the adjustment to interest expense for the issuance of the senior subordinated notes with an assumed annual interest rate of 9.5%:

(10) Reflects our proposed issuance of $200.0 million aggregate principal amount of senior subordinated notes ($194.0 million estimated net proceeds) to pay down existing debt and provide cash for operating purposes. (11) Reflects the proceeds from the primary issuance of common stock ($140.3 million estimated net proceeds) to pay down existing debt and provide cash for operating purposes. (12) Reflects the pending acquisition of an indirect 45% interest in a methanol production plant and a 50% interest in two affiliated companies for a non-interest bearing note to an affiliate. (13) Reflects our proposed distribution of a non-interest bearing note payable to CMS Enterprises. 32 37 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in an understanding of our historical financial position and results of operations for each of the three years in the period ended December 31, 1999 and our unaudited historical financial data as of and for the nine months ended September 30, 1999 and 2000. Our historical consolidated financial statements and notes thereto included elsewhere in this prospectus contain detailed information that should be referred to in conjunction with the following discussion. Additional financial information appears in this prospectus under "Unaudited Pro Forma Consolidated Financial Data." GENERAL We are an independent oil and natural gas company engaged in the exploration, development and acquisition of oil and natural gas properties in the U.S. and six other countries. Our oil-producing assets are concentrated in Africa (Equatorial Guinea, the Republic of Congo (Brazzaville) and Tunisia) and South America (Venezuela and Colombia), and our gas-producing assets are concentrated in the U.S. (Texas, Wyoming and Louisiana), Tunisia and Equatorial Guinea. The following events have recently had, and will continue to have, a significant impact on our results of operations and financial condition: - our acquisition in October 1999 of an additional 11.5% interest in the Bioko Permit offshore Equatorial Guinea and the initiation of an accelerated development project related to the Alba Field; - our pending acquisition from CMS Gas Transmission of an indirect 45% interest in a methanol production plant under construction in Equatorial Guinea for a note in the principal amount of approximately $137.0 million and the expected commencement in May 2001 of gas sales to the plant and production of methanol by the plant; - the disposition in March 2000 of our Michigan oil and gas producing properties, consisting principally of Antrim Shale natural gas properties, for approximately $162.9 million in cash; - the disposition in June 2000 of our oil-producing interests in Ecuador, consisting of Block 16 and related fields in the Oriente Basin of the Ecuadorian Amazon region, for approximately $95.8 million in cash; - our exploration and development activities relating to our Powder River Basin and West Texas properties and related expected increases in production; - our development activities in the Marine Exploration I Permit offshore the Republic of Congo (Brazzaville); - our acquisition of a 100% working interest in the Torbellino Block in Colombia, adjacent to the Espinal and Abanico Blocks in which we have interests, and the drilling of an aggregate of four new producing development wells and one new producing exploration well since January 1999 in the latter two blocks; and - the anticipated drilling of four new development wells in the La Palma Field and one exploration well in the Socuavo Field in the Colon Block in Venezuela. See "Business and Properties -- Recent Developments" "-- International Oil and Gas Operations" and "-- Domestic Oil and Gas Operations." We follow the successful efforts method of accounting for our 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 that 33 38 property on our 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 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. We periodically utilize hedging arrangements, such as options, futures and swap agreements, with respect to portions of our oil and natural gas production to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. We may employ these hedging arrangements with respect to some or all of that portion of our annual oil and natural gas production which is sold at variable or market-sensitive pricing when we view market prices as favorable compared to our projections of future prices. For the nine months ended September 30, 2000, the portion of our oil and natural gas production sold at variable pricing was approximately 4.0 MMBbls (73% of our oil production) and 10.3 Bcf (75% of our natural gas production). In connection with this offering, we expect to adopt new policies and procedures to govern our hedging. Under these policies and procedures, the objective of our hedging program will be to protect the amount of our cash flow required for debt service and firm capital expenditures. The hedging plan will be approved by our board of directors based on recommendations by our management. For purposes of these procedures, firm capital expenditures are considered those: - which, if not made, would expose us to material loss, including legal liability for breach of contract or penalty or property forfeiture; or - associated with projects expected to pay out in two years or less. The risks to be managed are commodity price and basis risks. For a more detailed description of our hedging arrangements, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Transactions." To the extent utilized, these hedging arrangements tend to have the effect of decreasing susceptibility of our cash flows to fluctuations in oil and natural gas prices. However, these arrangements also limit the benefits we realize if prices increase. With respect to the Marine I Permit in the Congo, we have entered into a price sharing agreement with BP Amoco Corporation providing for the sharing of revenues upon oil prices exceeding a benchmark price, which is currently set at $15.19 per barrel for 2000 and is adjusted annually by changes in the Consumer Price Index. The license governing our properties in Venezuela is an oil service contract whereby we receive a fee per barrel produced and delivered to Petroleos de Venezuela S.A. Additionally, we receive a fee for reimbursement of various capital expenditures. Our per barrel fees relating to this production are generally significantly lower than market prices for oil. The volumes presented represent actual production with respect to which we are paid a per barrel fee. Through March 2000, we generated significant amounts of nonconventional fuels (Section 29) tax credits as a result of the sale of natural gas produced from Antrim Shale and, to a lesser extent, tight sands wells. For instance, for the year 1999, we generated approximately $13.0 million of Section 29 tax credits; for the first quarter of 2000, we generated Section 29 tax credits of approximately $3.0 million. Due to the sale of our Michigan Antrim Shale properties in March 2000, we do not expect that we will generate significant Section 29 tax credits thereafter. See "Risk Factors" for more information to assist in an understanding of our results of operations and financial position. 34 39 RESULTS OF OPERATIONS Nine Months Ended September 30, 1999 Compared to Nine Months Ended September 30, 2000 The following table sets forth our selected oil and gas operating statistics for the nine-month periods ended September 30, 1999 and 2000: Selected Oil and Gas Operating Statistics

--------------- (1) Adjusted to reflect amounts received or paid under contracts entered into to hedge the price of a portion of production, including $8.0 million and $41.5 million paid for settlement of oil hedging contracts in the nine-month periods ended September 30, 1999 and 2000, respectively, and $1.1 million received and $2.3 million paid for settlement of natural gas hedging contracts in the nine-month periods ended September 30, 1999 and 2000, respectively. Without giving effect to this price hedging, the overall average oil price per barrel would have been $12.27 and $21.38, and the overall average natural gas price per Mcf would have been $1.98 and $2.75, for the nine-month periods ended September 30, 1999 and 2000, respectively. See note 9 to our consolidated financial statements included elsewhere in this prospectus. Revenues Oil and Condensate. Oil and condensate revenues increased $17.5 million, or 30%, to $76.3 million for the nine months ended September 30, 2000 over the comparable period in 1999 as a result of the average market price of oil and condensate (adjusted for hedging) increasing $3.04, or 28%. We reported oil and condensate production of 5,510 MBbls for the nine months ended September 30, 2000, an increase of 65 MBbls from 5,445 MBbls for the nine months ended September 30, 1999. Production was higher in Venezuela (by 276 MBbls) due to the completion of the two wells in the La Palma Field, West Texas (by 188 MBbls) due to the completion of 34 wells in the Devonian and Spraberry formations, Colombia (by 151 MBbls) due to the completion of three wells in the Espinal Block, Equatorial Guinea (by 132 MBbls) 35 40 due to the additional interest we acquired in October 1999 and the completion of two Alba wells, and other (by 3 MBbls), partially offset by lower production from Ecuador (by 513 MBbls) and Michigan (by 172 MBbls) due to the sale of those assets during the period. Natural Gas. Natural gas revenues decreased $3.9 million, or 10%, to $35.7 million for the nine months ended September 30, 2000 over the comparable period in 1999 as a result of a 5.6 Bcf, or 29%, decline in production, which was partially offset by the overall average net natural gas price (adjusted for hedging) increasing $0.54 per Mcf. The decrease in volumes was due to lower production from Michigan (by 8.9 Bcf) due to the sale of those assets and Freshwater Bayou (by 0.8 Bcf), which was partially offset by increased production in West Texas (by 2.4 Bcf) due to the drilling in the Devonian and Spraberry prospects, Venezuela (by 0.7 Bcf) due to the drilling of the Espinal Block wells, Powder River (by 0.6 Bcf) due to our drilling program there, and other (by 0.4 Bcf). Other Operating. Other operating revenues increased $3.7 million, or 132%, to $6.5 million for the nine months ended September 30, 2000, from $2.8 million for the nine months ended September 30, 1999. Other operating revenues includes $4.7 million and $2.1 million of NGL revenues for the nine-month periods ending September 30, 2000 and 1999, respectively. The increase was due to (1) a $12.41, or 164%, per barrel increase in the average NGL price, which was partially offset by reduced volume due to the sale of the Michigan assets, and (2) an increase in other income in Tunisia (by $0.7 million) and Congo (by $0.2 million). Cost and Expenses Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expenses decreased $3.3 million, or 10%, to $28.5 million for the nine months ended September 30, 2000, from $31.8 million for the nine months ended September 30, 1999, due primarily to reduced production volumes as a result of the sale of the Michigan and Ecuador assets. Our overall DD&A rate for the nine months ended September 30, 2000 was $3.54 per Boe, which did not change materially from the comparable period in 1999. Exploration Expense. Exploration costs increased $0.1 million, or 2%, to $6.2 million for the nine months ended September 30, 2000, compared to the comparable period in 1999. The increase in exploration costs was due primarily to higher impairments of non-producing leasehold (by $0.9 million) which was partially offset by lower geological and geophysical costs (by $0.8 million). Operating and Maintenance. Operating and maintenance, or O&M, expenses increased $3.2 million, or 8%, to $40.9 million for the nine months ended September 30, 2000 compared to the comparable period in 1999. The increase was due primarily to our increased working interest and production in Equatorial Guinea (by $2.6 million), initial production in the Powder River Basin (by $1.6 million) and West Texas (by $1.1 million), increased activity in Venezuela (by $1.0 million), and increased operations overhead costs (by $0.8 million) and plug and abandonment costs (by $0.5 million), which were partially offset by reduced costs due to the sale of our Michigan (by $4.1 million) and Ecuador (by $0.1 million) properties and other reductions (by $0.2 million). General and Administrative. General and administrative, or G&A, expenses of $14.8 million for the nine months ended September 30, 2000 was $3.7 million, or 34%, higher than the comparable period in 1999. The increase in G&A was due primarily to higher information services costs (by $1.6 million) and reduced G&A costs billed to third parties (by $1.9 million) in the nine months ended September 30, 2000, due to the sale of our Michigan assets, and due to other costs (by $0.2 million). Production and Other Taxes. Production and other taxes increased $0.8 million, or 32%, to $3.3 million for the nine months ended September 30, 2000 as compared to the comparable period in 1999, primarily due to an adjustment of a potential state tax liability recorded in 1999. Other Income and Expense. Other income and expense increased $32.0 million to $32.8 million for the nine months ended September 30, 2000 as compared to the comparable period in 1999. The increase was due to recording gains on the sale of our Ecuador ($24.7 million) and Michigan ($9.4 million) assets 36 41 and increased interest income on affiliate loans (by $0.5 million), which was partially offset by losses on the sale of other assets and other non-operating costs (by $2.6 million). Interest Expense, Net of Capitalized Interest. Interest expense increased $1.4 million, or 14%, for the nine months ended September 30, 2000 as compared to the comparable period in 1999. The increase was due to higher average interest rates of 7.47% for the period ended September 30, 2000, as compared to 6.15% for the nine months ended September 30, 1999, and a reduction of interest capitalized by $1.3 million, which was partially offset by lower borrowings under our credit facility. Our long-term debt balance as of September 30, 2000 was $130.5 million, compared to $195.7 million as of September 30, 1999. Income Taxes. Income tax benefit of $2.5 million decreased $7.3 million, or 74%, for the nine months ended September 30, 2000 as compared to the comparable period in 1999. The decrease in the tax benefit was due to reduced Section 29 tax credits (by $5.9 million) as a result of the sale of our Michigan assets, as well as an increase in taxable domestic income. Pretax Operating Income and Earnings Our pretax operating income for the nine months ended September 30, 2000 increased $12.8 million, or 106%, to $24.9 million, from $12.1 million for the nine months ended September 30, 1999. Net income increased $36.1 million, or 282%, to $48.9 million in the nine months ended September 30, 2000 from $12.8 million for the nine months ended September 30, 1999. Year Ended December 31, 1999 Compared to Year Ended December 31, 1998 The following table sets forth our selected oil and natural gas operating statistics for 1998 and 1999: Selected Oil and Gas Operating Statistics

--------------- (1) Adjusted to reflect amounts received or paid under contracts entered into to hedge the price of a portion of production, including $20.3 million paid for settlement of oil hedging contracts in the year ended December 31, 1999 and $2.9 million received and $0.1 million paid for settlement of natural gas hedging contracts in the years ended December 31, 1998 and 1999, respectively. Without giving effect to this price hedging, and the overall average oil price per barrel would have been $9.14 and 37 42 $14.12, and the overall average natural gas price per Mcf would have been $2.01 and $2.07, for the years ended December 31, 1998 and 1999, respectively. See note 9 to our consolidated financial statements included elsewhere in this prospectus. Revenues Oil and Condensate. Oil and condensate revenues of $82.6 million in 1999 increased $15.8 million, or 24%, over 1998 revenues of $66.8 million due to a $2.19, or 24%, per barrel increase in the overall oil price, net of hedging. We reported oil and condensate production of 7,288 MBbls in 1999, a decrease of 21 MBbls over the prior year's volumes of 7,309 MBbls. Production was lower due to normal production declines in Colombia (by 233 MBbls), Venezuela (by 221 MBbls), Ecuador (by 181 MBbls) and the U.S. (by 12 MBbls), partially offset by higher production due to the completion of new wells in Congo (by 375 MBbls), Tunisia (by 168 MBbls) and Equatorial Guinea (by 83 MBbls). Natural Gas. Natural gas revenues decreased $1.4 million, or 3%, in 1999 to $54.7 million, compared to $56.1 million in 1998, as a result of a 0.1 Bcf decline in production and a $0.05 per Mcf decline in overall gas price, net of hedging. The decrease in volumes was due to lower production due to normal production declines in Michigan (by 1.6 Bcf), partially offset by increased production due to new wells in Tunisia (by 1.2 Bcf) and start-up production in West Texas (by 0.3 Bcf). Other Operating. Other operating revenues of $5.5 million increased $1.1 million, or 26%, in 1999 from the prior year. Other operating revenue includes $3.7 million and $2.8 million from the sale of NGLs for 1999 and 1998, respectively. The increase was due to a $2.68, or 40%, per barrel increase in the average NGL price (by $0.9 million) and an increase in other revenues (by $0.2 million). Cost and Expenses Depreciation, Depletion and Amortization. DD&A expenses increased $5.7 million, or 15%, to $43.8 million in 1999, from $38.1 million the prior year due primarily to higher depletion rates. Our overall 1999 DD&A rate of $3.62 per Boe increased $0.48 per Boe, or 15%, compared to $3.14 per Boe in 1998. Exploration Expense. Exploration costs decreased $9.5 million, or 50%, to $9.5 million in 1999, from $19.0 million in 1998, due primarily to our successful exploratory program in 1999. In 1998, we expensed $13.7 million of exploratory dry holes compared to no dry hole costs in 1999. Partially offsetting the decrease in exploratory dry holes was an increase in delay rentals and lease expense of $3.2 million over 1998, which included a $2.0 million write-off of undeveloped leasehold in the Cote d'Ivoire and higher exploration overhead costs ($0.6 million). Operating and Maintenance. O&M expenses increased $7.7 million, or 17%, to $52.0 million in 1999, from $44.3 million the prior year. The higher O&M costs reflect increased costs in Ecuador (by $2.5 million) due to higher operating costs, Tunisia (by $1.7 million) due to a new well beginning production in mid-1998, Equatorial Guinea (by $1.5 million) due to our increased interest in the project, and Colombia (by $0.3 million), and higher operational overheads of $3.6 million due to setup costs of new district offices in Midland, Texas, Denver, Colorado and Gillette, Wyoming, which were partially offset by lower O&M costs incurred in the U.S. (by $0.9 million), Venezuela (by $0.8 million) and Congo (by $0.2 million). General and Administrative. G&A expenses of $16.8 million increased $2.5 million, or 18%, from $14.3 million in 1998. The increase in G&A costs primarily reflects the higher costs related to shared corporate services provided by our parent, costs related to relocate processes performed by our Traverse City office to Houston and other general and administrative costs. Production and Other Taxes. Production and other taxes decreased $1.3 million, or 25%, to $4.0 million in 1999, compared to $5.3 million in 1998, due primarily to an adjustment of a potential state tax liability. 38 43 Other Income. Other income decreased $0.5 million, or 42%, to $0.7 million in 1999, compared to $1.2 million in 1998, due primarily to an increase in the recording of non-operating reserves of $1.2 million, which was partially offset by a increase in gains on the sale of miscellaneous oil and gas assets of $0.7 million. Interest Expense, Net of Capitalized Interest. Net interest expense of $13.6 million decreased $2.5 million, or 16%, in 1999 from $16.1 million in 1998 reflecting certain months with higher debt levels. Interest expense capitalized in 1999 increased by $1.6 million, from $0.4 million in 1998, to $2.0 million in 1999, due to ongoing development in the Powder River Basin in Wyoming and in West Texas. The average interest rate per annum before capitalized interest was 7.0% compared to 6.6% per annum in 1998. Income Taxes. Income tax benefit of $14.1 million increased $0.2 million, or 1%, in 1999 compared to $13.9 million in 1998, due primarily to changes in pre-tax income of our domestic corporations. Pretax Operating Income and Earnings. Our 1999 pretax operating income increased $10.3 million, or 161%, to $16.7 million, from $6.4 million in 1998. Net income of $17.9 million in 1999 increased $12.5 million, or 231%, compared to $5.4 million in 1998 as a result of increased operating revenues. Year Ended December 31, 1998 Compared to Year Ended December 31, 1997 The following table sets forth our selected oil and natural gas operating statistics for 1997 and 1998. Selected Oil and Gas Operating Statistics

--------------- (1) Adjusted to reflect amounts received or paid under contracts entered into to hedge the price of a portion of production, including $1.8 million received for settlement of oil hedging contracts in the year ended December 31, 1997 and $7.4 million paid and $2.9 million received for settlement of 39 44 natural gas hedging contracts in the years ended December 31, 1997 and 1998, respectively. Without giving effect to this price hedging, the overall average oil price per barrel would have been $13.65 and $9.14, and the overall average natural gas price per Mcf would have been $2.35 and $2.00, for the years ended December 31, 1997 and 1998, respectively. See note 9 to our consolidated financial statements included elsewhere in this prospectus. Revenues Oil and Condensate. Oil and condensate revenues decreased $24.5 million, or 27%, to $66.8 million in 1998 over 1997 as a result of a $4.78, or 34%, per barrel decrease in the overall average market price for oil to $9.14 per barrel in 1998, from $13.92 per barrel (adjusted for hedging) in 1997, which was partially offset by an increase in production of 0.7 MMBbls. Production was higher in Venezuela (by 0.5 MMBbls), Equatorial Guinea (by 0.1 MMBbls) and Tunisia (by 0.1 MMBbls). Natural Gas. Natural gas revenues decreased $0.3 million in 1998 to $56.1 million, from $56.4 million in 1997 as a result of a 0.7 Bcf, or 2%, decrease in natural gas production, partially offset by a $0.04, or 2%, per Mcf greater average natural gas price, net of hedging. Other Operating. Other operating revenues decreased by $4.1 million, or 48%, in 1998 from 1997. Other revenue includes NGL revenues of $2.8 million and $5.1 million in 1998 and 1997, respectively. The decline in other revenue was due primarily to the $9.17, or 58%, per barrel decline in the average NGL price and the decline of miscellaneous income of $1.8 million. Cost and Expenses Depreciation, Depletion and Amortization. DD&A expenses decreased $10.0 million, or 21%, to $38.1 million in 1998, compared to $48.1 million in 1997, due to an overall depletion rate of $3.14 per Boe in 1998, compared to $4.22 per Boe in 1997. Exploration Expenses. Exploration costs declined in 1998 by $8.7 million, or 31%, to $19.0 million, from $27.7 million in 1997. The decline in exploration costs was due primarily to a decline in exploratory dry holes being expensed in 1998 of $3.5 million, or 20%, to $13.7 million from $17.2 million in 1997, along with a decline in geological and geophysical costs being expensed, per the successful efforts method of accounting, of $1.5 million in 1998, from $6.9 million being expensed in 1997. Operating and Maintenance. O&M expenses of $44.3 million in 1998 reflect an increase of $0.1 million over 1997. Expenses increased in the LPG plant in Equatorial Guinea and due to start up costs in Tunisia, which was partially offset by lower operating costs in Ecuador as a result of switching from diesel to gas powered generators. General and Administrative. G&A expenses decreased $2.3 million, or 14%, to $14.3 million in 1998 compared to 1997. The decrease was due primarily to the costs associated with the relocation of our corporate offices from Jackson, Michigan to Houston, Texas in 1997. Production and Other Taxes. Production and other taxes decreased $0.2 million, or 4%, in 1998 compared to $5.5 million in 1997, due primarily to lower domestic gas production. Other Income. Other income decreased $11.9 million, or 91%, to $1.2 million in 1998 compared to 1997. The decrease was due primarily to gains on the sale of our interests in Yemen ($9.3 million), Thunder Bay Pipeline ($1.1 million) and Wellcorps ($0.5 million) and a transfer fee earned on the sale of an office building in Houston ($1.1 million) recognized in 1997. Interest Expense, Net of Capitalized Interest. Net interest expense increased $0.4 million, or 3%, to $16.1 million in 1998, compared to $15.7 million in 1997, due to higher debt levels and slightly higher interest rates. Interest rates averaged 6.6% per annum in 1998 compared to 6.3% per annum in 1997. Our ending long-term debt balance of $230.4 million in 1998 increased $39.1 million, or 20%, compared to $191.3 million in 1997. 40 45 Income Taxes. The income tax benefit of $13.9 million in 1998 was $6.9 million higher than the $7.0 million tax benefit in 1997. Lower income in 1998 was the primary cause of the higher tax benefit. Pretax Operating Income and Earnings. In 1998, our pretax operating income decreased $7.8 million, or 55%, to $6.4 million, from $14.2 million in 1997. Net income decreased $13.2 million, or 71%, to $5.4 million, from $18.6 million in 1997, reflecting lower operating income and an increase in net interest expense, partially offset by increase in tax benefit. LIQUIDITY AND CAPITAL RESOURCES General Our primary needs for capital, in addition to the funding of ongoing operations, have been for the exploration, development and acquisition of oil and natural gas properties and the repayment of principal and interest on debt. Our primary sources of liquidity have been net cash provided by operating activities, borrowings under our credit facility and borrowings and equity infusions from our parent, CMS Enterprises, as needed. We budget our exploration and development, or E&D, expenditures based upon projected cash flows, and subject to contractual commitments, routinely adjust our E&D expenditures in response to changes in projected cash flows. We believe that cash generated from operations, the aggregate estimated net proceeds to us from this offering and our concurrent offering of senior subordinated notes and borrowing capacity under our credit facility as we expect it to be in place upon completion of this offering will be sufficient to meet our liquidity and capital requirements through the end of 2001. However, we may need to access the public or private capital markets to fund our growth and capital expenditures thereafter. In particular, we may need to access these markets or to repatriate offshore income, with resultant triggering of U.S. income taxes and increases to our deferred tax account, to fund our domestic activities and debt repayment. Operating Activities Net cash provided by (used in) operating activities was $(1.1) million for the nine months ended September 30, 2000, $66.8 million, $89.5 million and $75.4 million in the years ended December 31, 1999, 1998 and 1997, respectively. The decline in 2000 of net cash provided by operating activities was due to increased receivables due to higher oil and natural gas prices, timing of payment of income tax receivables and an increase in deferred tax asset due to the sale of the Michigan and Ecuador assets. The decline in net cash provided by operating activities in 1999 was due to lower oil prices in December 1999 and timing of crude oil liftings in the Congo. The increase in net cash provided by operating activities in 1998 was due to an increase in current liabilities associated with Powder River and our Michigan assets. Financing Activities Our total debt outstanding at September 30, 2000 was $130.5 million, a decrease of $105.9 million, or 45%, from $236.4 million at December 31, 1999, which was an increase of $6.0 million, or 3%, from $230.4 million at December 31, 1998. Credit Facility. Our credit agreement with Bank One, N.A., as agent, which we call our credit facility, currently provides a maximum lending commitment of $225.0 million. The credit facility is subject to an aggregate borrowing base limitation equal to the estimated loan value of our oil and natural gas reserves, subject to exclusions, including exclusions for most of our international reserves, based upon forecast rates of production and commodity pricing factors, as periodically redetermined by the banks which are parties to the credit facility. The banks have broad discretion in determining which of our reserves to include in the borrowing base. As of September 30, 2000, the borrowing base, and thus the total amount available for borrowing, was $100.0 million. Of that amount, $65.0 million in borrowings and a $5.0 million undrawn letter of credit were outstanding at September 30, 2000. As of December 31, 1999, 41 46 the borrowing base, and accordingly, the total amount available for borrowing under the credit facility, was $210.0 million. Of that amount, $175.0 million in borrowings was outstanding at December 31, 1999. We expect that, in connection with the concurrent offering of our senior subordinated notes, our borrowings under the credit facility will be repaid in full and that the credit facility will be renegotiated or replaced with a credit facility having a maximum lending commitment of $75.0 million. Under the terms of the credit facility, we must maintain: (1) a ratio of total indebtedness to total capitalization of no more than 0.60 to 1; (2) a minimum tangible net worth, as defined, of $275 million, plus 50% of positive net income commencing with the quarter ended June 30, 1999, plus 50% of the net proceeds of any equity sale, as defined; (3) a ratio of EBITDA to interest greater than 2.75 to 1; and (4) a ratio of consolidated debt to adjusted cash flow of no greater than 4.25 to 1 for any fiscal quarter ending at any time on or after December 31, 1999 to and including September 30, 2000, or 3.75 to 1 for any fiscal quarter thereafter. Restrictive covenants under the credit facility include limitations on our indebtedness and contingent obligations, as well as restrictions on liens, investments, affiliate transactions and sales of assets. In addition, the banks have the right to require us to repay all advances under the credit facility within 90 days after notification to the banks that (1) CMS Energy no longer beneficially owns a majority of our outstanding voting stock or (2) all or substantially all of our assets are sold. The following table sets forth our status with respect to the financial covenants under the credit facility as described above as of the dates indicated:

--------------- (1) As defined in the credit facility. CMS Energy Note. In 1995, we issued a note, which we call the CMS Energy Note, in the principal amount of approximately $61.3 million to CMS Enterprises, which in turn assigned it to CMS Energy in connection with the transfer of the common stock of Terra Energy Ltd. by CMS Energy to CMS Enterprises and then by CMS Enterprises to us. Also in 1995, we issued another note in the principal amount of approximately $6.5 million to CMS Energy in connection with borrowings made to repay $6.5 million of indebtedness of a subsidiary immediately upon our acquisition of the subsidiary. In 1997, we made payments totaling $10.0 million to extinguish the latter note and to reduce the CMS Energy Note. In 1999, the CMS Energy Note was amended to extend its maturity to April 15, 2009 and to suspend cash interest payments until April 14, 2004. Until that date, interest accrues and is added to the outstanding debt balance. This note bears interest at the three-month London Interbank Offered Rate, or LIBOR, plus 2.0% per year. Amounts outstanding under this note are subordinate to the credit facility, and we are subject to limitations on our obligation to make payments on it in the event of a default under the terms of the credit facility. As of September 30, 2000 and December 31, 1999, $62.2 million and $58.5 million, respectively, of principal and $1.2 million and $1.0 million, respectively, of accrued interest were outstanding on the CMS Energy Note. We intend to use a portion of the aggregate net proceeds to us from this offering and our concurrent offering of senior subordinated notes to repay this note. Acquisition of Methanol Plant. We have agreed to purchase, prior to completion of this offering, CMS Gas Transmission's 50% voting interest in Atlantic Methanol Capital and two affiliated companies. Through Atlantic Methanol Capital, CMS Gas Transmission indirectly owns a 45% interest in a methanol production facility currently in the late stages of construction on Bioko Island in Equatorial Guinea. We will purchase these interests by issuance to CMS Gas Transmission of a note in the principal amount of approximately $137.0 million. We intend to use a portion of the aggregate net proceeds to us from this offering and our concurrent offering of senior subordinated notes to repay this note. 42 47 Atlantic Methanol Capital was established for the purpose of, among other things: - issuing $125.0 million of 10 7/8% Series A-1 Senior Secured Notes relating to the financing of CMS Gas Transmission's indirect interest in the plant; and - issuing $125.0 million of 8.95% Series A-2 Senior Secured Notes relating to the financing of Noble Affiliates, Inc.'s indirect interest in the plant. Each of the Series A-1 Notes and the Series A-2 Notes are limited recourse and independent of each other, and holders of the notes have recourse only to the respective security for the notes. Atlantic Methanol Capital used a portion of the proceeds of the sale of the Series A-1 Notes and the Series A-2 Notes to purchase a portion of the respective ownership interests in CMS Methanol Company and Samedan Methanol, which prior to this transaction were wholly-owned subsidiaries of CMS Gas Transmission and Noble, respectively. CMS Gas Transmission and Noble contributed to Atlantic Methanol Company the remainder of their respective ownership interests in CMS Methanol Capital and Samedan Methanol as equity for their ownership in Atlantic Methanol Capital. CMS Methanol Company and Samedan Methanol each have an indirect 45% ownership interest in Atlantic Methanol Production Company, LLC, which is constructing and will operate the methanol plant. Although the Series A-1 Notes are not our direct obligations, we expect to make payment of interest on these notes, which will amount to approximately $13.6 million per year, using our available sources of capital. Under the terms of our acquisition of CMS Gas Transmission's indirect interest in the methanol facility, CMS Gas Transmission will be responsible for interest accrued on the Series A-1 Notes through April 30, 2001. We expect Atlantic Methanol Production to refinance the Series A-1 Notes at or prior to their maturity from the proceeds of a project financing. If Atlantic Methanol Production were unable to refinance the Series A-1 Notes, we expect to access the public or private capital markets to retire these notes. The occurrence of certain events will constitute a "trigger event" under the indenture relating to the Series A-1 Notes, including: - at least 120 days prior to the maturity date, which will be in December 2004 at the latest, an amount equal to the repayment amount has not been deposited with the indenture trustee; - a downgrading of CMS Energy unsecured senior debt to "B2" or below by Moody's Investor Service or "B+" or below by Standard & Poor's Corporation and a decline in the closing price of the CMS Energy common stock, which continues for three consecutive trading days, to below $24.00, after adjustment to reflect any stock split, stock dividend or certain other events occurring with respect to that common stock; - default by CMS Energy resulting in the acceleration of any of its indebtedness in an aggregate amount in excess of $25.0 million, which acceleration has not been rescinded within ten days after written notice of default; or - entry of final judgments against CMS Energy or any restricted CMS Energy subsidiary aggregating in excess of $25.0 million which remain undischarged or unbonded for a period of 60 days. Upon the occurrence of a trigger event, the indenture trustee for the Series A-1 Notes, with some exceptions, so long as those notes have not been repaid may, or at the direction of holders of not less than 25% in aggregate principal amount of all notes outstanding will, cause the remarketing of shares of CMS Energy preferred stock, which have been placed in a share trust to secure the notes, through a mandatory remarketing arrangement and to use the net proceeds thereof to repay the Series A-1 Notes. In addition, the holders of the notes have the right to look to the other security for the notes for repayment. The security for the notes includes, in addition to the proceeds from the remarketing of the CMS Energy preferred stock, CMS Energy's guarantee of all interest payments due on the notes, subject to a $75.0 million aggregate limit, and 60% of our stock of CMS Methanol Company, which indirectly owns our interest in the methanol production facility. 43 48 We have agreed to indemnify CMS Energy and CMS Gas Transmission for any costs or expenses incurred by either of them in connection with repayment of the principal of or interest on the Series A-1 Notes. Note Payable to CMS Enterprises. Prior to the completion of this offering, we expect to distribute to our parent company, CMS Enterprises, a note payable in the principal amount of $39.0 million. This note will not bear interest and will become due and payable upon completion of this offering. We intend to use a portion of the aggregate net proceeds to us from this offering and our concurrent offering of senior subordinated notes to repay this note. Senior Subordinated Notes. Concurrently with the completion of this offering, we expect to issue and sell, in the public or private markets, $200.0 million aggregate principal amount of senior subordinated notes. We expect that the net proceeds of this offering, after deducting transaction expenses and issuance discount, will be approximately $194.0 million. We expect that the indenture under which the senior subordinated notes will be issued will contain limitations on incurrence of additional debt, payment of dividends or distributions, sale or pledge of assets and other ordinary covenants. For a discussion of our expected use of the proceeds from this offering, we refer you to "Use of Proceeds." Investing Activities Our recent E&D investments have focused on a balance of acquisitions and the development of existing properties, acquiring proved producing reserves in established core areas (for example, the acquisition of our additional interest in Equatorial Guinea), as well as establishing new producing leasehold positions in core areas (Devonian, Spraberry and Clearfork plays in West Texas and the Powder River Basin in Wyoming and Montana) for our development. For the nine-month periods ended September 30, 2000 and 1999, our E&D expenditures were $85.5 million and $55.3 million, respectively, excluding $259.6 million and $1.2 million, respectively, in proceeds from asset sales. Our E&D expenditures of $151.0 million (net of $2.3 million in proceeds from asset sales) in 1999 represented an increase of $8.8 million, or 6%, over 1998. Our E&D expenditures of $142.2 million for the year ended December 31, 1998 were $67.6 million, or 91%, higher than E&D expenditures of $74.6 million for 1997. We have budgeted to spend approximately $152.6 million during 2000 and $166.0 million during 2001 for exploration, development, leasehold acquisitions and other capital expenditures. Our budget includes development costs that are contingent on the success of future exploratory drilling. We do not anticipate that our budgeted leasehold acquisition activities will include the acquisition of producing properties. We do not anticipate any significant abandonment or dismantlement costs through 2001. Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, natural gas and oil prices, industry conditions, decisions of operators and partners and the prices of oil field materials and services. HEDGING TRANSACTIONS We currently sell most of our natural gas and oil production under contracts that call for payment of a purchase price that is based on a published market reference price. To reduce our risk that market prices will fall, we have, from time to time, entered into hedging contracts. These hedging contracts take the form of swaps or other hedge contracts which we enter into with CMS Enterprises, CMS MST or another affiliate. The hedging contracts take several forms. Some are straight swaps (which fix a price for a specified expiration date and a specified quantity of product), some are collars (put options purchased by us matched to call options sold by us establishing a floor and ceiling price) and some are put options. We pay a premium for the put options (which when purchased by us permit us to sell at the stated floor price). Hedging contracts protect us from declines in prices but, except for puts, they also limit the benefit we would otherwise have experienced from rising prices. Put contracts allow us to benefit from price increases but involve a premium expense. We generally have followed the practice of hedging some portion 44 49 of the anticipated production from our proved developed producing reserves but have not hedged any part of anticipated production from our undeveloped or unproved reserves. For the nine months ended September 30, 2000, increasing prices have allowed us to sell oil and gas at higher prices but have also produced losses on the hedge positions of approximately $43.8 million. With respect to the production that we have hedged, the net result of the prices we have received on sales and the hedge losses have approximated the results of sales at the prices fixed in the hedge contracts. We did not enter into any put option hedges (other than in connection with collars) during the period. The following chart summarizes the hedging contracts in place with respect to production in future periods. WTI refers to the market for West Texas Intermediate Crude Oil. Brent refers to the Brent market for North Sea oil. Heating oil refers to the #6 fuel oil 1% market. One MMBtu approximates one Mcf of gas.

We account for these contracts as hedges; accordingly, any changes in market value and gains or losses from settlements are deferred and recognized at the time the hedged transaction is completed. For a discussion of expected changes in the policies applicable to our hedging, we refer you to "Business and Properties -- Hedging Objectives." YEAR 2000 We estimate that the total direct cost for the Year 2000 effort through September 30, 2000 was approximately $0.6 million. Approximately $0.4 million and $0.2 million were expensed in 1999 and the nine months ended September 30, 2000, respectively. We had no Year 2000-related costs for the years ended December 31, 1997 and 1998. Replacement equipment and software were capitalized or expensed in accordance with our normal accounting policies. The effect of writing off the net book value of equipment or software that was not Year 2000 compliant is included in the above estimates. INFLATION AND CHANGE IN PRICES Our revenues and the value of our oil and natural gas properties have been and will be affected by changes in oil and natural gas prices. Our ability to obtain additional capital on satisfactory terms is also substantially dependent on oil and natural gas prices, which are subject to seasonal and other fluctuations 45 50 that are beyond our ability to control or predict. Although some of our costs and expenses are affected by the level of inflation, inflation has not had a significant effect on our results of operations during any of the three years in the period ended December 31, 1999. NEW ACCOUNTING POLICIES In June 1998, the Financial Accounting Standards Board, or FASB, issued SFAS No. 133, "Accounting for Derivative Investments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. In June 1999, the FASB issued SFAS No. 137 which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. A company may implement SFAS 133 as of the beginning of any fiscal quarter after issuance, however, the statement cannot be applied retroactively. We do not plan to adopt SFAS 133 early. We have not yet assessed the effectiveness of our September 30, 2000 derivative contracts and therefore cannot quantify the impact of adoption of SFAS 133. If we assume that all the derivative contracts at September 30, 2000 were ineffective, we would have recorded a current liability of approximately $25.2 million, representing the fair value of all derivatives at that date. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK Commodity Risk Our major commodity risk exposure is the pricing applicable to our oil and natural gas production. Realized commodity prices received for our production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Historically, prices received for oil and gas production have been volatile and unpredictable and we expect price volatility, and the effects of this volatility, to continue. For the nine months ended September 30, 2000 a 10% fluctuation in the prices received for oil and gas production would have had an approximate $4.0 million impact on our revenues and operating income. We periodically enter into hedging activities on a portion of our projected proved developed oil and natural gas production through a variety of financial and physical arrangements intended to support oil and natural gas prices as targeted levels and to manage our exposure to oil and natural gas price fluctuation. We may use futures contracts, swaps, options and fixed-price physical contracts to hedge commodity prices. Realized gains or losses from our price risk management activities are recognized in oil, condensate and natural gas production revenues when the associated production occurs. We do not hold or issue derivative instruments for trading purposes. In 1999, and in the nine-month period ending September 30, 2000, we recognized a net loss of $20.3 million and $41.5 million, respectively, from hedging activities that decreased oil and condensate production revenues and $0.1 million and $2.3 million, respectively, from hedging activities that decreased natural gas production revenues. For a discussion of our recent hedging activity and expected changes in the policies applicable to our hedging, we refer you to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Transactions" and "Business and Properties -- Hedging Objectives," respectively. Interest Rate Risk The carrying value of our debt approximates fair value. At December 31, 1999 and September 30, 2000, we had $235.6 million and $130.5 million, respectively, of long-term debt, primarily represented by an unsecured revolving credit facility totaling $175.0 million and $65.0 million, respectively, and notes to 46 51 our indirect parent, CMS Energy, totaling $58.5 million and $62.2 million, respectively. The notes payable to CMS Energy are expressly subordinated to the credit facility. The credit facility matures May 25, 2002 and bears interest at LIBOR plus a percentage based on the percentage of the borrowing base outstanding and also requires a facility fee. The notes payable to CMS Energy bear interest at the three-month LIBOR rate plus 200 basis points and mature April 15, 2009. In regard to the credit facility and the notes payable to CMS Energy, the results of a 10% fluctuation in short-term interest rates would have had an approximate $1.4 million and $0.9 million impact on our cash flow for the year ended December 31, 1999 and the nine months ended September 30, 2000, respectively. 47 52 BUSINESS AND PROPERTIES OVERVIEW We are an independent energy company engaged in oil and natural gas acquisition, exploration and development activities principally in Africa, the U.S. and South America. Formed in 1967, we have grown our operations through acquisition and exploration and are currently one of the larger U.S. based independent oil and natural gas companies. Our strategy is to increase reserves, production, cash flow and earnings by committing our resources to regions with significant growth prospects and properties that allow us to leverage our extensive operating and technical expertise. On a pro forma basis, excluding our Michigan and Ecuador properties which we recently sold, we have grown our production and estimated proved reserves at annualized rates of 12.4% and 25.4%, respectively, from January 1, 1995 through September 30, 2000. We have achieved these impressive growth rates by employing a lower-risk, disciplined international and domestic acquisition, exploration and development strategy. Internationally, we have been active in Africa and South America for over a decade and currently have concessions which have significant production, reserves and, we believe, reserve growth potential. We are actively exploiting our properties in Equatorial Guinea, Colombia, Venezuela and the Republic of Congo (Brazzaville). Domestically, we have built an attractive reserve base and acreage holdings located principally in the Powder River Basin of Wyoming and Montana and the Permian Basin of West Texas. We are actively exploring and developing these domestic properties which have increasing production and, we believe, significant reserve growth potential. We expect to spend approximately $166.0 million in 2001 to further develop our existing reserves and to pursue attractive exploration opportunities. We believe that our regional operating philosophy, acreage and reserve positions and management expertise provide us with significant opportunities for growth. As of September 30, 2000, we had estimated proved reserves of 212.0 million barrels of oil equivalent, or MMBoe, with a net present value (before taxes) of $1,164.7 million. Of these reserves, 92% were classified as proved developed. We operate properties accounting for approximately 91% of these estimated proved reserves, allowing us to better manage expenses, capital allocation and the timing of exploration and development activities. On a pro forma basis, excluding our recently sold Michigan and Ecuador properties and after giving effect to the acquisition in October 1999 of an additional interest in the Bioko Permit offshore Equatorial Guinea, we produced 7.1 MMBoe in 1999 and 6.3 MMBoe for the nine months ended September 30, 2000. 48 53 The following table summarizes by region our estimated proved reserves as of September 30, 2000 and our average daily net production during the three months ended September 30, 2000:

--------------- (1) For purposes of this table, oil and condensate reserves includes 12.2 MMBbls of international NGLs, and oil and condensate production includes 0.9 MBbls of international NGLs. ACQUISITIONS AND DISPOSITIONS OF PROPERTIES Acquisition of Additional Working Interest in Equatorial Guinea In October 1999, we purchased an additional 11.5% working interest in the Bioko Permit offshore Equatorial Guinea for cash of approximately $53.3 million, increasing our working interest in this property from 42.5% to 54.0%. Acquisition of Methanol Production Facility We have agreed to purchase, prior to the completion of this offering, a 50% interest in Atlantic Methanol Capital, which owns an indirect 90% interest in a 2,500 metric ton per day methanol production facility currently in the late stages of construction on Bioko Island in Equatorial Guinea. We will purchase this interest from CMS Gas Transmission, a subsidiary of CMS Enterprises, by issuance of a note in the principal amount of approximately $137.0 million, which will be repaid with a portion of the aggregate proceeds from this offering and our concurrent offering of senior subordinated notes. Atlantic Methanol Capital has issued $125.0 million of limited recourse indebtedness, which is secured by, among other things, a pledge of 60% of the interest we expect to acquire. We believe that ownership of an interest in this methanol facility will allow us to further enhance the value of our natural gas reserves offshore Equatorial Guinea. Prior to our agreement to acquire this facility, our return on this natural gas was limited by the $0.25 per MMBtu selling price under a 20-year contract to sell up to 126,500 MMBtu per day of natural gas to the facility. Given that natural gas is typically the largest cost component in the production of methanol, we believe this gas sales contract will position this facility to be one of the lowest cost methanol producers in world markets. Recent Dispositions of Non-Strategic Assets Michigan Properties. In March 2000, we sold substantially all of our Michigan oil and gas properties for cash of approximately $162.9 million. The properties consisted principally of natural gas wells in the 49 54 Devonian Antrim Shale formation in the northern portion of Michigan's lower peninsula, most of which we operated, but in which we held only an average 20% working interest. The properties had estimated net proved reserves as of January 1, 2000 of 167.0 Bcf of gas (27.8 MMBoe) and 0.8 MMBbls of oil, condensate and NGLs, representing approximately 11.3% of our estimated total proved reserves on that date. During the three months ended March 31, 2000, average daily net production from these properties was approximately 47.0 MMcf of gas. Ecuador Properties. In June 2000, we sold all of our 14% non-operated working interest in our Ecuador oil assets, consisting of Block 16 and related oil fields in the Oriente Basin of the Ecuadorian Amazon region. We received cash consideration of approximately $95.8 million for these properties. These properties had estimated net proved reserves as of June 30, 2000 of 23.5 MMBbls of oil, representing 11.0% of our estimated total proved reserves on that date. During the three months ended June 30, 2000, average daily net production from these properties was 4.0 MBbls. INTERNATIONAL OIL AND GAS OPERATIONS Africa Republic of Equatorial Guinea. Our interests in Equatorial Guinea in West Africa represented 70.1% of our estimated proved reserves as of September 30, 2000 and contributed 19.8% of our production for the three months ended September 30, 2000. We own a 54.0% working interest in the Bioko Permit, which we operate offshore Equatorial Guinea from our West Africa regional offices located in the city of Malabo on Bioko Island. We have a net 138,854 undeveloped acres in this permit. We have participated in the drilling of seven gross wells in the Alba Field located on the block, all of which have encountered hydrocarbons and five of which are producing gas/condensate. We extract liquefied petroleum gas, or LPG, from an LPG extraction plant located on Bioko Island. Average daily gross production for the three months ended September 30, 2000 was 7,300 barrels of condensate (3,400 barrels net to us), 2,093 barrels of LPG plant products (900 barrels net to us), and 9.5 MMcf of natural gas (4.8 MMcf net to us), exclusive of flared gas, or an aggregate of 11.0 MBoe (5.1 MBoe net to us). As of September 30, 2000, estimated gross proved reserves in the field totaled 89.7 MMBbls of condensate (38.6 MMBbls net to us), 28.3 MMBbls of plant products (12.2 MMBbls net to us) and 1,363.7 Bcf of natural gas (587.1 Bcf net to us), or an aggregate of 345.3 MMBoe (148.6 MMBoe net to us). In 1999, we initiated a $115.0 million accelerated development project with respect to the Alba Field. We have constructed and installed two new drilling platforms, drilled four wells, all of which were successful, and constructed an additional pipeline to plant facilities on Bioko Island. Two of the wells are gas/condensate producers, and two are gas injection wells. By early 2001, we expect gross natural gas production to increase from 90 MMcf per day, including flared gas, to up to 225 MMcf per day, with up to 126,500 MMBtu per day of production to be sold for $0.25 per MMBtu under a 20-year contract with Atlantic Methanol Production Company LLC, in which we have agreed to acquire an indirect 45% interest from CMS Gas Transmission. The gas will be used as feed stock for a 2,500 metric ton per day methanol plant currently under construction on Bioko Island. This gas is "stranded" and otherwise would be flared or reinjected into the reservoir. We plan to reinject any unused gas into the reservoir. The limits on the Alba Field have not yet been defined by drilling. We expect to drill one additional appraisal well in early 2001. We also have under way engineering studies that could result in additional facilities enhancements to the Alba project which would have the objective of increasing our production of condensate and LPG plant products. Our exploration group has identified several additional prospects on the Bioko Block. One of these prospects will be drilled and tested by early 2001. 50 55 Other participants in the Bioko Permit are Samedan of North Africa, Inc. (an affiliate of Noble Affiliates, Inc.) and GLOBEX International. The production sharing contract governing the Alba Field has a term of 50 years commencing May 2, 1990. In August 2000, we acquired farm-in rights from Ocean Equatorial Guinea Corporation to its Block D offshore Equatorial Guinea, which is a 199,781 acre block adjacent to and immediately west of the Bioko Block. Under the farm-in, we are required to drill one exploratory well. By drilling this exploratory well, which our personnel in Equatorial Guinea expect to do in early 2001, we will earn a 50% operating working interest in any oil and gas discoveries on the block, except that, with respect to one prospect on the block, our working interest will be 100%. However, by virtue of the election of our Bioko Block co- venturers regarding their participation in the farm-in, our working interests will be reduced to 40% in the block generally and 80% with respect to the one prospect on the block. We have identified a number of additional prospects on this block, and we may drill up to two additional exploratory wells on the block later in 2001. Republic of Congo (Brazzaville). Our interests in the Congo in West Africa represented 6.9% of our estimated proved reserves as of September 30, 2000 and contributed 22.2% of our production for the three months ended September 30, 2000. We own a 50% working interest in, and we operate from our Pointe Noire, Congo offices, the Marine I Exploration Permit offshore the Congo. Average daily gross production during the three months ended September 30, 2000 was 13,174 barrels of oil (5,665 barrels net to us). As of September 30, 2000, estimated gross proved reserves totaled 40.1 MMBbls of oil (14.7 MMBbls net to us). The Marine I Exploration Permit covers three discoveries: the Yombo Field and the Masseko and Youbi discoveries. There are currently 32 wells located in the Yombo Field: 26 oil wells, five water injection wells and one shut-in well. Oil is produced into our self-contained floating production, storage and off-loading vessel, or FPSO, the tanker Conkouati, anchored on site. The oil is processed into No. 6 fuel oil on the Conkouati. The vessel's storage capacity is over one million barrels of oil. Every 30 to 45 days, the processed fuel oil is offloaded from the Conkouati to another vessel for transportation to market. By mid-year 2001, we plan to further develop the Yombo Field by drilling five horizontal wells, which may include high-angle side tracks of existing wells. Other participants in this project are The Nuevo Congo Company, Nuevo Congo, Ltd. and Societe Nationale des Petroles du Congo, or SNPC, the state oil company, whose interest is being carried by the other participants. The convention governing the Marine I Permit has a maximum term of 30 years, commencing March 15, 1989. We also have an agreement with BP Amoco Corporation providing for sharing of revenues upon oil prices exceeding $15.19 per barrel. Under the terms of the convention, our interest will revert to 25% once costs spent on behalf of SNPC are recovered. In late 1995, the Hydrocarbons Ministry of the government of the Republic of Congo (Brazzaville) notified us as operator of the Marine I Exploration Permit offshore Congo, which includes the Yombo Field, that it would like to convert the concession governing the participants' interests in this project to a production sharing contract. The Congolese government had significant leverage to request changes due to its broad governmental and regulatory powers. Discussions with the Congolese government concerning its request began in March 1996 but were subsequently suspended. The discussions recently resumed and will likely continue into 2001. Although the Congolese government has indicated that it desires to achieve economic parity in effecting the contract conversion, we cannot currently predict what impact, if any, these discussions will have on the project's economics, and we cannot assure you that these discussions or their outcome will not have a material adverse effect on our estimated reserves or financial results. Republic of Tunisia. Our interests in Tunisia represented 4.3% of our estimated proved reserves as of September 30, 2000 and contributed 9.3% of our production for the three months ended September 30, 2000. We operate five wells in two concession areas in Tunisia from our Tunis offices. One of the wells is 51 56 located on the El Franig Concession, where we have a 55% working interest, and four are located on the Baguel Concession, where we have a 49% working interest. Average daily gross production for the three months ended September 30, 2000 was 1,940 barrels of oil (1,016 barrels net to us) and 17.6 MMcf of natural gas (8.5 MMcf net to us), or an aggregate of 4,856 Boe (2,432 Boe net to us). As of September 30, 2000, estimated gross proved reserves in the El Franig and the Baguel Concessions totaled 7.9 MMBbls of oil (3.2 MMBbls net to us) and 83.6 Bcf of natural gas (36.0 Bcf net to us), or an aggregate of 21.8 MMBoe (9.3 MMBoe net to us). Two wells, one gas well and one oil well, were drilled in 1998 and 1999, respectively, on the Baguel Concession. The remaining three wells are gas wells with high condensate yields. All of our gas wells are connected to production facilities. The oil well is currently under long-term test and evaluation. We also plan to evaluate other opportunities in the area. The other participant in the concessions is Entreprise Tunisienne d'Activites Petrolieres, or ETAP, the state oil company. The association contract governing these concessions has a term of 50 years, commencing June 1987 for Baguel and January 1984 for El Franig. Republic of Cameroon. We own a 37.5% working interest in Blocks 1 and 6, known as the Kombe Permit, located onshore in the Douala Basin of the Republic of Cameroon. We are the operator of this permit, which has 183,636 net undeveloped acres. The permit area includes the M'Via, N'Koudou and Benda oil and gas discoveries, which were made before we acquired our interest. In 1998 and 1999, we re-entered the M'Via No. 1 well, an oil well, which tested at a rate of 1,090 barrels of oil per day. Also in 1999, we drilled one additional M'Via well, a 4,900 foot offset to the first M'Via discovery. This field remains under evaluation. We expect to drill an offset delineation well in the M'Via Field and an exploration well on the permit in 2001. During 1999, we completed the acquisition of aeromagnetic and aerogravity surveys and completed the reprocessing of 1,300 miles of 2-D seismic data. To date, in 2000, we have obtained an additional 125 miles of 2-D seismic data. In addition, we applied for a permit covering 296,768 acres in Block OLHP-2, which is adjacent to and immediately northwest of the Kombe Permit. If acquired, we will operate and own a 37.5% working interest in this permit. As a result of encouraging test data on the M'Via discovery well and remapping of the surrounding area, we have identified a number of exploration prospects on Block OLHP-2. Other participants in the Kombe Permit are GLOBEX Cameroon, L.L.C. and Societe Nationale des Hydrocarbures, the state oil company. The convention governing the permit has a term of 25 years from first commercial production of hydrocarbons, which has not yet occurred. South America Republic of Venezuela. Our interests in Venezuela represented 6.4% of our estimated proved reserves as of September 30, 2000 and contributed 23.0% of our production for the three months ended September 30, 2000. We own a 43.8% working interest in the Colon Block, which we acquired in 1994 in the second bid round of Venezuela's Marginal Fields Reactivation Program. There are seven productive fields on this 789,168 acre block: West Tarra, Los Manueles, Las Cruces, Bonito, Socuavo, Rosario and La Palma. Average daily gross production for the three months ended September 30, 2000 was 12,421 barrels of oil (5,434 barrels net to us), and 8.5 MMcf of gas (2.9 MMcf net to us), or an aggregate of 13.1 MBoe (5.9 MBoe net to us). As of September 30, 2000, estimated gross proved reserves in the block totaled 28.6 MMBbls of oil (12.5 MMBbls net to us) and 12.5 Bcf of gas (6.4 Bcf net to us), or an aggregate of 31.0 MMBoe (13.6 MMBoe net to us). The operator of this block has acquired 3-D seismic data covering the La Palma structure and has begun further development drilling. The other participants in the Colon Block are Tecpetrol de Venezuela, S.A., as operator, and Coparex Latina de Petroleos S.A. The operating services agreement governing the block currently has a term of 20 years and expires December 31, 2015. Under this agreement, we receive a fee per barrel produced and 52 57 delivered to Petroleos de Venezuela S.A. Additionally, we receive a fee for reimbursement of various capital expenditures. Our per barrel fees relating to this production are generally significantly lower than market prices for oil. Republic of Colombia. Our interests in Colombia represented 2.0% of our estimated proved reserves as of September 30, 2000 and contributed 6.6% of our production for the three months ended September 30, 2000. We own interests in two adjacent onshore blocks in the Upper Magdelena Valley, the Espinal Block and the Abanico Block. We own a 15% working interest in the Espinal Block and a 100% working interest (subject to government participation at 50%) in the Abanico Block. Average daily gross production for these blocks for the three months ended September 30, 2000 was 13,679 barrels of oil (1,699 barrels net to us). As of September 30, 2000, estimated gross proved reserves in the area totaled 21.6 MMBbls of oil (4.3 MMBbls net to us). The Espinal Block contains three producing fields: the Matachin Norte Field, the Matachin Sur Field and the Purificacion Field. At the end of 1998, there were eight producing wells on this 48,230 acre block, two in the Matachin Norte Field, three in the Matachin Sur Field and three in the Purificacion Field. Since then, three additional horizontal wells have been drilled and successfully completed in the Matachin Norte Field. All of the wells in the Espinal Block are oil wells, and all are operated by Petrobras Colombia Limited, which owns a 30% interest in the block. Empresa Colombiana de Petroleos, or Ecopetrol, the state oil company, owns the remaining working interest in the block. The operator of this block has recently obtained additional 3-D seismic data. The participation risk contract governing the Espinal Block has a maximum term of 28 years, commencing October 1987. We are the operator of the Abanico Block, which covers 251,680 acres. In 1999, we drilled and tested a successful exploration well on this block. During 2000, we began production of the well, transporting the oil by truck to facilities owned and operated by Ecopetrol. In addition, we drilled two offset wells to further define the structure, one of which is currently producing. The other well will be used for water injection. We expect to drill one additional Abanico well and to construct a gathering system in 2001. We also expect to reprocess 2-D seismic data, as well as obtain new 2-D seismic data, in 2001. The association contract governing the Abanico Block has a six-year exploration term and a maximum term of 28 years, commencing October 1996. In January 2000, we acquired a 100% working interest (subject to government participation at 30%) in an adjacent third block, the Torbellino Block. The Torbellino Block covers 79,600 acres. It is located north of and on trend with our producing fields in the Espinal Block and is likewise on trend with and southwest of a significant recent oil discovery, the Guando Field, operated by Petrobras Colombia Limited on the Boqueron Block. We believe that the Torbellino Block holds significant exploration potential, and we expect to commence drilling on it in 2001. We also expect to reprocess 2-D seismic data, as well as obtain new 2-D seismic data, in 2001. The association contract governing the Torbellino Block has a six-year exploration term and a maximum term of 28 years, commencing March 28, 2000. DOMESTIC OIL AND GAS OPERATIONS Powder River Basin The Powder River Basin represented 2.6% of our estimated proved reserves as of September 30, 2000 and contributed 2.7% of our production for the three months ended September 30, 2000. In late 1998, we acquired a 50% undivided interest in approximately 497,000 undeveloped acres in this basin, which spans the Wyoming-Montana border. This acreage is owned jointly with Pennaco Energy, Inc. and we each operate approximately 50% of it. In 1999, we acquired an additional 32,000 undeveloped net acres. We are now one of the larger holders in this region, which is estimated to hold up to 25 trillion cubic feet, or Tcf, of recoverable natural gas. As of September 30, 2000, we had participated in the drilling of 491 coal bed methane gas wells in the basin, of which 223 were producing. We expect production from most or all of the remaining wells to commence upon dewatering and/or completion of additional gathering lines and facilities. We operate 183 of the producing wells in which we have an interest. Average daily gross 53 58 production on our acreage for the three months ended September 30, 2000 was 8.1 MMcf (4.2 MMcf net to us). Estimated gross proved reserves at September 30, 2000 were 84.0 Bcf of gas (33.8 Bcf net to us). Our strategy with respect to the Powder River Basin is to continue coal bed methane gas drilling by project area, with each of the undeveloped project areas in which we own an interest tested through a limited pilot drilling program. Based upon expected spacing regulations, more than 3,000 gross (1,500 net to us) coal bed methane wells could ultimately be drilled on our acreage. Our drilling to date has been in five of 13 project areas in which we have an interest. Drilling, completion and facility costs in the basin have averaged approximately $80,000 per well and reserve additions have averaged over 280 MMcf per well. We plan to participate in the drilling of an additional 40 wells in the fourth quarter of 2000. Our Powder River Basin coal bed methane project is managed through our Denver and Gillette offices, both of which opened in July 1999. West Texas The Permian Basin in West Texas represented 6.4% of our estimated proved reserves as of September 30, 2000 and contributed 9.4% of our production for the three months ended September 30, 2000. We currently hold, have under option or have the right to earn by drilling 3,724 developed and 76,380 undeveloped net acres in this area. We have interests in 35 gross producing Devonian, Pennsylvanian, Mississippian Spraberry and Clearfork formation wells (32.3 net to us). We operate all of these wells. Average daily gross production on our acreage for the three months ended September 30, 2000 was 14.2 MMcf of gas (9.2 MMcf net to us), and 1,248 barrels of oil or condensate, (827 barrels net to us), or an aggregate of 3,615 Boe (2,391 Boe net to us). Estimated gross proved reserves at September 30, 2000 were 65.5 Bcf of gas (48.3 Bcf net to us) and 7.2 MMBbls of condensate (5.3 MMBbls net to us), or an aggregate of 18.1 MMBoe (13.5 MMBoe net to us). Horizontal drilling program. The successful application of horizontal drilling technology in the Permian Basin has made the development of low permeability reservoirs known to contain hydrocarbons very economic. We believe that the acreage we currently hold or have the option to lease is sufficient to support an active horizontal drilling program for at least the next three years. We believe this technology has a wide application in low permeability reservoirs throughout the Permian Basin, and we plan to continue to acquire prospective acreage throughout the basin in pursuit of these opportunities. Since late 1999, we have drilled 16 horizontal natural gas wells in the Devonian formation in Midland and Upton Counties, each drilled to a vertical depth of approximately 12,000 feet and then extending horizontally varying distances ranging from 4,000 to 9,500 feet. As of September 30, 2000, 13 of these wells were producing, two were awaiting completion and one was shut in. We own an average 87.7% working interest in these wells. In July 2000, we drilled our first horizontal well to the Pennsylvanian formation, about 1,000 feet above the Devonian, in Midland County. The well tested at a rate of 480 barrels of condensate per day. Since then, we have drilled one additional Pennsylvanian horizontal well. We hold an average working interest of 95% in these wells. In August 2000, we acquired 1,920 net leasehold acres, with an option to acquire an additional 21,000 acres, in Lynn County for horizontal well development in the Mississippian formation. We hold a 100% working interest in the acreage. We completed our first Mississippian well in November 2000 and anticipate drilling several more development wells in order to define the capability of the field. Spraberry/Clearfork drilling program. We own and operate 20 oil wells in the Spraberry and Clearfork formations in the SRH Field in Reagan County. We own a 100% working interest in these wells and hold leasehold rights to 13,960 net undeveloped acres, which we plan to further develop in 2001 and thereafter. In July 2000, we entered into an agreement with Texaco Land Company covering 14,880 undeveloped acres in Midland County. The agreement gives us the right to earn the acreage by drilling Spraberry wells on 160 acre units. Through September 30, 2000, we have drilled four successful Spraberry wells, all of 54 59 which have been completed, on this acreage. Currently, we have three rigs drilling on the acreage. We plan to drill up to 150 wells through 2005 to fully develop and earn the acreage. We manage our Permian Basin program from our Midland, Texas office, which we opened in 1998. Louisiana Our Louisiana properties, consisting principally of our interest in the Freshwater Bayou Field operated by Unocal Corporation, represented 1.0% of our estimated proved reserves as of September 30, 2000 and contributed 6.6% of production for the three months ended September 30, 2000. We currently hold 4,134 net leasehold acres and have interests in 19 gross producing wells (5.3 net to us). Our average daily net production for this area for the three months ended September 30, 2000 was 9.5 MMcf of natural gas and 107 net barrels of oil. As of September 30, 2000, we had 2.1 MMBoe of estimated proved reserves in Louisiana. METHANOL PRODUCTION AND MARKETING We have agreed to purchase, prior to the completion of this offering, CMS Gas Transmission's 50% interest in each of Atlantic Methanol Capital and two affiliated companies. Atlantic Methanol Capital, incorporated in the Cayman Islands, owns a 90% interest in a 2,500 metric ton per day methanol production facility currently in the late stages of construction on Bioko Island in Equatorial Guinea. We believe that ownership of an interest in this methanol facility will allow us to further enhance the value of our natural gas reserves in Equatorial Guinea. We will purchase CMS Gas Transmission's interest in Atlantic Methanol Capital by issuance of a note in the principal amount of approximately $137.0 million, which is equal to CMS Gas Transmission's cost in its interest, inclusive of funds necessary to complete the facility and accrued interest on the Series A-1 Notes through April 30, 2001. We and CMS Gas Transmission have agreed that this amount represents the fair market value of this interest inclusive of these items. We will repay this note with a portion of the aggregate proceeds from this offering and our concurrent offering of senior subordinated notes. Atlantic Methanol Capital has issued $125.0 million of limited recourse indebtedness which is secured by, among other things, a pledge of 60% of the interest we expect to acquire in the plant. CMS Gas Transmission currently owns a 50% voting interest in each of Atlantic Methanol Capital, AMPCO Marketing LLC and AMPCO Services LLC. An affiliate of Noble Affiliates, Inc., or Noble, owns the other 50% voting interest in each of these three companies, with management of these companies shared by CMS Gas Transmission and Noble or their respective affiliates. Atlantic Methanol Capital, through CMS Methanol Company and Samedan Methanol, owns indirectly a 90% interest in Atlantic Methanol Production Company, LLC, which is constructing and will operate the methanol production facility. The other 10% of Atlantic Methanol Production is owned by Guinea Equatorial Oil and Gas Marketing Ltd., a corporation controlled by the Republic of Equatorial Guinea. The methanol production facility is currently scheduled for completion in May 2001. Construction costs are estimated to total approximately $448 million plus $38 million of capitalized interest and other corporate costs relating to CMS Gas Transmission's ownership interest. Upon completion, the methanol facility is expected to be one of the lowest cost methanol producers in the world. Natural gas is typically the largest cost component in the production of methanol, and Atlantic Methanol Production has entered into a long-term natural gas supply agreement which provides the facility with up to 126,500 MMBtu per day of natural gas for 20 years at a fixed price of $0.25 per MMBtu. The source of the natural gas is the Alba Field, in which we and an affiliate of Noble have respective 54.0% and 34.8% working interests. As of September 30, 2000, Ryder Scott Company, L.P., our independent petroleum engineers, estimated the Alba Field's gross proved reserves at 1.36 Tcf of natural gas and 104.1 MMBbls of oil, condensate and NGLs. Methanol is a commodity, and therefore it is difficult for producers of methanol to distinguish their production to the consumer on any basis other than price. Given the importance of natural gas in the production of methanol, we believe this facility will have significant pricing flexibility to cope with the cyclical nature of the methanol business due to the favorable terms of the natural gas supply agreement. 55 60 Accordingly, we understand that Atlantic Methanol Production intends to capitalize on the facility's competitive cost structure. Atlantic Methanol Production has contracted with Mitsui OSK Lines, Ltd. for the construction and time chartering of two approximately 45,000 dead weight metric ton methanol transport vessels for terms of approximately 15 years commencing in the first and second quarter of 2001, respectively. These tankers will transport methanol from the production facility to market. AMPCO Marketing LLC, a Michigan limited liability company, intends to enter into an agreement with Atlantic Methanol Production whereby it will purchase some of the methanol from the production facility and resell it in U.S. markets. Atlantic Methanol Production is entering into an agreement with a European broker to provide methanol to European customers. AMPCO Marketing LLC and Atlantic Methanol Production may, from time to time, enter into additional marketing contracts or arrangements to sell methanol. AMPCO Services LLC, a Michigan limited liability company, has agreed to provide management consulting services to Atlantic Methanol Production and AMPCO Marketing LLC. RESERVES The following table sets forth our net interest in estimated quantities of developed and undeveloped proved oil and natural gas reserves at September 30, 2000 as prepared by Ryder Scott Company, our independent petroleum engineers.

--------------- (1) For purposes of this table, oil and condensate includes 12.2 MMBbls of international NGLs. We retained Ryder Scott Company to prepare the above reserve estimates at September 30, 2000. A letter from Ryder Scott relating to their reserve report, dated November 10, 2000, is included as Appendix A to this prospectus. Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of those reserves can be estimated with reasonable certainty, or from existing wells where a relative major expenditure is required to establish production. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in this prospectus represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of the estimates, and these revisions may be material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. As an operator of domestic oil and natural gas properties, we have filed Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by Public Law 93-275. There are differences between the reserves as reported on Form EIA-23 and as reported in this prospectus. The 56 61 differences are attributable to the fact that Form EIA-23 requires that an operator report on the total reserves attributable to wells which are operated by it, without regard to ownership (i.e., reserves are reported on a gross operated basis, rather than on a net interest basis). The following table sets forth, at September 30, 2000, the standardized measure of discounted future cash flows attributable to our estimated proved reserves as of September 30, 2000:

The standardized measure of discounted future cash flows from estimated production of our proved oil and gas reserves is presented in accordance with the provisions of Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities" (SFAS No. 69). In computing this data, we have used assumptions and estimates, and we cannot assure you that these assumptions and estimates will be indicative of future economic conditions. We caution you against interpreting this information as a forecast of future economic conditions or revenues. We determined future net cash flows by using estimated quantities of proved reserves and the periods in which they are expected to be developed and produced based on September 30, 2000 economic conditions. We used September 30, 2000 prices of $5.13 per MMBtu of natural gas at the Henry Hub Index and $30.83 per barrel of oil at the Cushing spot market, except where we have fixed and determinable prices provided by contract. We reduced the resulting estimated future cash flows by estimated future costs to develop and produce the proved reserves based on September 30, 2000 cost levels, but not for debt service and general and administrative expenses. For additional information on our reserves, the net present value of future cash flows and the standardized measure of discounted future net cash flows to be derived from our reserves, see the risk factor relating to our reserves under "Risk Factors" and Supplemental Information -- Oil and Gas Producing Activities in our consolidated financial statements included elsewhere in this prospectus. WELLHEAD VOLUMES, PRICES AND PRODUCTION COSTS The following table sets forth information on our net wellhead production volumes and average wellhead prices received for sales of oil and condensate, natural gas and natural gas liquids, and average production costs of sales volumes during the years ended December 31, 1997, 1998 and 1999 and the nine- month periods ended September 30, 1999 and 2000 and pro forma for the year ended December 31, 1999 57 62 and the nine months ended September 30, 2000, giving effect to the dispositions of our Michigan and Ecuador properties as if these transactions had occurred on the first day of each period.

--------------- (1) Adjusted to reflect amounts received or paid under our hedging arrangements. 58 63 ACREAGE The following table sets forth the developed and undeveloped acreage in which we held a leasehold, mineral or other interest at September 30, 2000. Excluded is acreage in which our interest is limited to owned royalty, overriding royalty and other similar interests.

The following table sets forth the developed and undeveloped acreage in which we held a contractual right to earn an interest by drilling as of September 30, 2000:

The tables above do not reflect the undeveloped acreage set forth in the table below in which we do not yet have an interest but with respect to which we hold exclusive negotiating rights with the countries noted. We expect negotiations on these new areas to be completed by March 31, 2001.

59 64 PRODUCING WELL SUMMARY The following table sets forth the number of gross and net producing oil and natural gas wells in which we have ownership interests at September 30, 2000:

Producing wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. We had no multiple completions. DRILLING ACTIVITIES During the years ended December 31, 1997, 1998 and 1999, and the nine months ended September 30, 2000, we spent approximately $117.8 million, $100.8 million, $98.9 million and $85.5 million, respectively, for exploratory and development drilling. We drilled or participated in the 60 65 drilling of gross and net wells as set out in the table below for the periods indicated (with our participation in Michigan Antrim gas and Powder River Basin coal bed methane gas drilling shown separately):

--------------- (1) Includes properties we formerly owned in Indiana and Ohio. Due to the success rates typically associated with drilling Michigan Antrim gas and Powder River Basin coal bed methane gas wells, the table above sets forth separately our participation in these drilling activities. We also participated in other wells through farm-outs, acreage contributions and other nonpaying interests. All of our drilling activities are conducted on a contract basis with independent drilling contractors. We own no material drilling equipment. 61 66 Excluding the drilling of Powder River Basin methane gas wells, at September 30, 2000, we were participating in the drilling or completion of one gross (0.5 net) wells in Africa, and eight gross (eight net) wells in the U.S. On that date, we were participating in the drilling of four Powder River Basin coal bed methane gas wells. MARKETING Natural Gas All of our domestic natural gas production is sold to various buyers on a spot market basis or under contracts providing for variable or market sensitive pricing. All of our Powder River Basin gas has been sold to CMS Field Services or an affiliate at market sensitive prices. During the three months ended September 30, 2000, sales to CMS Field Services or an affiliate accounted for approximately 1.1% of our consolidated revenues. We expect that, upon completion of this offering, a substantial part of our domestic gas production will be sold to CMS MST. For a discussion of the agreements expected to govern these sales, we refer you to "Relationship and Certain Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Gas Sales Agreements." We do not believe the loss of any purchaser of our domestic natural gas would have a material adverse effect on our financial condition or results of operations due to the likely availability of other purchasers for our production at comparable prices. Our Tunisian natural gas production is sold under a long-term contract at indexed prices tied to regional oil prices to La Societe Tunisienne de l'Electricite et du Gas, the state electric and gas utility. Our natural gas production in Venezuela is sold to Petroleos de Venezuela S.A. under a long-term contract at fixed prices tied to volumes produced. We have entered into a long-term contract to sell up to 126,500 MMBtu per day of our natural gas production in Equatorial Guinea to our affiliate, Atlantic Methanol Production, at $0.25 per MMBtu as feed gas for the methanol plant currently under construction on Bioko Island. Oil We market our oil and condensate production from our Equatorial Guinea and Congo properties under contracts based on market index prices on a cargo lot basis. Oil production from our Colombian and Permian Basin properties is sold under contracts based on market index prices. All of our oil production from Equatorial Guinea, Congo and Colombia is currently brokered by Texon L.P., which is a 50% owned subsidiary of CMS MST. We expect that, upon completion of this offering, all of this oil production, as well as our Permian Basin oil production, will be marketed by CMS MST. For a discussion of the agreements expected to govern these sales, we refer you to "Relationship and Certain Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Oil Marketing Agreement." Oil production from our Venezuelan project is owned and delivered by us to Petroleos de Venezuela S.A. We have not experienced any material inability to market our oil as a result of limited access to transportation space. HEDGING OBJECTIVES We periodically enter into oil and natural gas price hedge arrangements to mitigate our exposure to price fluctuations on the sale of oil and natural gas. Prior to the adoption of the hedging policies and procedures discussed below, our hedging arrangements have been directed primarily by CMS Energy with a view to benefiting the entire CMS Energy group of affiliated companies. In connection with this offering, we expect to adopt new policies and procedures to govern our hedging. Under these policies and procedures, the objective of our hedging program will be to protect the amount of our cash flow required for debt service and firm capital expenditures. The hedging plan will be approved by our board of directors based on recommendations by our management. For purposes of these procedures, firm capital expenditures are considered those: - which, if not made, would expose us to material loss, including legal liability for breach of contract or penalty or property forfeiture; or - associated with projects expected to pay out in two years or less. 62 67 The risks to be managed are commodity price and basis risks. For a description of our recent hedging activity, we refer you to "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Transactions." For a description of agreements we expect to enter into with CMS MST relating to the execution of our hedging objectives, we refer you to "Relationship and Certain Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Hedging Agreements." TITLE TO PROPERTIES As is customary in the oil and natural gas industry, we make only a limited review of title to farmout acreage and to undeveloped domestic oil and natural gas leases upon execution of the contracts and leases. Prior to the commencement of drilling operations, we order a thorough title examination and curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects, we or the other operator of the project, rather than the seller of the undeveloped property, is typically responsible for curing any of these title defects at our expense. If we or the other operator were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on the property, we could suffer a loss of a portion of, or our entire investment in, the property. We have obtained title opinions on substantially all of our domestic producing properties and believe that we have satisfactory title to these properties in accordance with standards generally accepted in the oil and natural gas industry. Our oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other burdens which we believe do not materially interfere with the use or affect the value of the properties. In the case of our international interests, the host government generally owns the minerals. We contract with the government to explore, develop and produce oil and natural gas, and it is not customary to obtain title opinions on these properties. COMPETITION The oil and natural gas industry is highly competitive. We face competition in all aspects of our business, including acquiring reserves, leases, licenses and concessions, obtaining the equipment and labor needed to conduct our operations and marketing our oil and natural gas. Our competitors include multinational energy companies, government-owned oil and natural gas companies, other independent oil and natural gas concerns and individual producers and operators. Because both oil and natural gas are fungible commodities, the principal form of competition with respect to product sales is price competition. We believe that our competitive position is also affected by our geological and geophysical capabilities and ready access to markets for production. Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of our larger competitors may be better able to respond to factors such as changes in worldwide oil or natural gas prices or levels of production, the cost and availability of alternative fuels or the application of government regulations, which affect demand for oil and natural gas production and which are beyond our control. Moreover, many competitors have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek entry. We expect this high degree of competition to continue. The methanol business in which we intend to engage through our acquisition of an interest in Atlantic Methanol Capital is also highly competitive. Many of the competitors are larger and have greater financial resources than the methanol facility. These competitors of the methanol facility of Atlantic Methanol Capital also may operate multiple plants, offsetting some risks to which a single-plant producer such as the methanol facility may be subject. Methanol consumers, additionally, may prefer the security of purchasing from a multiple-plant producer. As a result, any level of demand established for the methanol facility's product may not be maintained. In addition, the methanol facility's business is based upon widely available technology. Accordingly, barriers to entry, apart from capital availability, may be low, and the entrance of new competitors into the industry may reduce the methanol facility's ability to capture improving profit margins in circumstances where overcapacity in the industry is diminishing. 63 68 GOVERNMENTAL REGULATION Our exploration, development, production and marketing operations are subject to regulation at the federal, state and local levels in the U.S. and by other countries in which we conduct business, including regulation relating to matters such as the exploration for and the development, production, marketing, pricing, transmission and storage of oil and natural gas, as well as environmental and safety matters. Failure to comply with these regulations could result in substantial liabilities to third parties or governmental entities, the payment of which could have a material adverse effect on our financial condition or results of operations. We believe that we are in substantial compliance with these laws and regulations. However, we cannot assure you that laws or regulations enacted in the future or the modification of existing laws or regulations will not adversely affect our exploration for or development, production or marketing of oil or natural gas. In addition, international properties, operations or investments may be adversely affected by: - local political and economic developments; - exchange controls; - currency fluctuations; - royalty and tax increases; - retroactive tax claims; - import and export regulations; - other foreign laws or policies; and - preparation of environmental impact statements and compliance with findings thereunder for wells on lands subject to these requirements, as well as by laws and policies of the U.S. affecting foreign trade, taxation and investment. Furthermore, in the event of a dispute arising from international operations, we may be subject to the exclusive jurisdiction of courts outside the U.S. or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the U.S. We may also be hindered or prevented from enforcing our rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity. U.S. Regulation The oil and natural gas industry is subject to various types of regulation by federal, state and local authorities in the U.S. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. Further, numerous departments and agencies, both federal and state, have issued rules and regulations affecting the oil and natural gas industry and its individual members, compliance with which is often difficult and costly and some of which may carry substantial penalties for non-compliance. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, consequently, affects its profitability. Inasmuch as these laws and regulations are frequently expanded, amended or reinterpreted, we are unable to predict the future cost or impact of complying with these regulations. Exploration and Production. Our exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes: - requiring permits for the drilling of wells; - maintaining bonding requirements in order to drill or operate wells; - regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandoning of wells; and - satisfactory completion of an environmental impact statement for wells on lands subject to these requirements. 64 69 Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we may produce from our wells, and to limit the number of wells or the locations at which we may drill. A portion of our oil and natural gas leases are granted by the federal government and administered by the Bureau of Land Management, or BLM, and the Minerals Management Service, or MMS, both of which are federal agencies. These leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders which regulate, among other matters, drilling and operations on these leases, calculation of royalty payments to the federal government and bonding requirements (and which are subject to change by the BLM and the MMS). The Mineral Lands Leasing Act of 1920 places limitations on the number of acres under federal leases that we may own in any one state. While subject to this law, we do not have sufficient federal lease acreage positions in any state or in the aggregate to be likely to be subject to these limitations in the foreseeable future. Sales of crude oil, condensate, and natural gas liquids by us are not currently regulated and are made at market prices, but these sales are affected by the cost of interstate pipeline transportation, which is regulated by the Federal Energy Regulatory Commission, or FERC. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates, which may affect transportation costs and delivered prices, and the FERC is presently reconsidering the appropriate index to utilize. In recent years, the FERC has also permitted interstate oil pipelines to charge market-based rates instead of cost-based rates upon a showing that markets are sufficiently competitive. Natural Gas Marketing and Transportation. Federal legislation and regulatory controls in the U.S. have historically affected the price of our natural gas production and the manner in which we may market our production. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. Later, in 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Our natural gas sales are affected by the availability, terms, and cost of interstate pipeline transportation, which is regulated by the FERC under the Natural Gas Act and the Natural Gas Policy Act. In an attempt to restructure the interstate pipeline industry with the goal of providing enhanced access to, and competition among, alternative natural gas suppliers, the FERC, commencing in April 1992, issued Order No. 636 and a series of related orders, which collectively we call Order No. 636, which have altered significantly the interstate transportation and sale of natural gas. Among other things, Order No. 636 required interstate pipelines to unbundle the various services that they had provided in the past, such as sales, transmission and storage, and to offer these services individually to their customers. By requiring interstate pipelines to "unbundle" their services and to provide their customers with direct access to pipeline capacity held by them, Order No. 636 has enabled pipeline customers to choose the levels of transportation and storage service they require, as well as to purchase natural gas directly from third-party merchants other than the pipelines and to obtain transportation of that gas on a non-discriminatory basis. The effect of Order No. 636 has been to enable us to market our natural gas production to a wider variety of potential purchasers. We believe that these changes generally have improved our access to transportation and have enhanced the marketability of our natural gas production. We believe that Order No. 636 has not had any material adverse effect on our ability to market and transport our natural gas 65 70 production. However, we cannot predict what new regulations may be adopted by the FERC and other regulatory authorities, or what effect subsequent regulations may have on our activities. In Order No. 637 and a related series of orders issued in 2000, the FERC revised its open access regulations to improve the efficiency of the gas market and to provide captive customers with the opportunity to reduce their cost of holding interstate pipeline capacity. Among other things, those FERC orders removed price ceilings for short-term released capacity, permitted pipelines to file for peak/off-peak and term differentiated rate structures, and revised regulations relating to scheduling procedures, capacity segmentation, and pipeline penalties to improve the efficiency and competitiveness of the pipeline grid. The FERC has reformulated its test for distinguishing between jurisdictional transportation facilities and gathering facilities, which are exempt from regulation under the Natural Gas Act. In the Sea Robin decision, issued on June 30, 1999 on remand from a Fifth Circuit opinion rendered in 1997, the FERC held that pipeline facilities previously classified as jurisdictional transportation facilities should be reclassified as gathering facilities. This decision could increase gas transmission costs and the regulatory scrutiny of natural gas gathering by state agencies. Non-U.S. Regulation Our international exploration, development and production of oil and natural gas are also subject to various types of governmental regulation. In addition, international projects in which we have an interest generally involve complex contractual relationships with the host government which often contain extensive provisions governing the operation of these projects. We may also be asked to comply with, and in some cases have committed to comply with, voluntary international standards developed by non-governmental entities, such as those promulgated by the International Standards Organization and the World Bank, in connection with obtaining financing for our operations. The matters addressed by these regulations, contractual provisions and standards include: - spacing and location of wells; - maximum rates of production from wells; - access to transportation facilities; - permissible volumes for transport; - well abandonment procedures; and - environmental protection. In addition, host governments often seek to insure that the local communities in the areas of activity are strengthened and developed with the view to a better social environment and that off-shore and coastal waters and on-shore areas remain suitable for other resource development projects. ENVIRONMENTAL MATTERS Extensive federal, state and local laws and regulations relating to health and environmental quality in the U.S. as well as environmental laws and regulations of other countries in which we operate affect nearly all of our operations. These laws and regulations: - set various standards regulating various aspects of health and environmental quality; - provide for penalties and other liabilities for the violation of those standards; and - establish, in certain circumstances, obligations to remediate current and former facilities and off-site locations. We believe that our policies and procedures in the area of pollution control, product safety and occupational health are adequate to prevent unreasonable risk of environmental and other damage, and of resulting material financial liability, in connection with our business. However, we could incur significant liability for damages, clean-up costs and/or penalties in the event of discharges into the environment, 66 71 environmental damage caused by previous owners of property purchased by us or non-compliance with environmental laws or regulations. This liability could have a material adverse effect on our financial condition or results of operations. Moreover, we cannot predict what environmental legislation or regulations will be enacted in the future or how existing or future laws or regulations will be administered or enforced. Compliance with more stringent laws or regulations, or more vigorous enforcement policies of regulatory agencies, could in the future require us to make material expenditures for the installation and operation of systems and equipment for remedial measures, all of which could have a material adverse effect on our financial condition or results of operations. For instance, legislation has been proposed in the U.S. Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to more stringent handling, disposal and clean-up requirements. If this legislation were to be enacted, it could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. State initiatives to further regulate the disposal of oil and natural gas wastes are also pending in various states, and these initiatives could have a similar impact. In addition, the issues of water withdrawal and discharge in the Powder River Basin is coming under increasing scrutiny. Citizens groups have become increasingly opposed to the development of new wells and are seeking to influence federal, state and local regulators to increasingly regulate this activity. This has prompted a temporary moratorium on issuance of new water discharge permits in Montana while the issue is further studied. MTBE, of which methanol is a component, is subject to a phase-out in California and is subject to similar scrutiny in other states and at the federal level. Finally, environmental regulations are becoming increasingly stringent and more vigorously enforced in other countries where we operate, raising similar concerns. Spill Control and Response Legislation The United States Oil Pollution Act of 1990, or OPA, and its related regulations impose a variety of requirements on persons who are or may be responsible for oil spills in waters of the U.S. Among other things, OPA requires owners and operators of facilities and vessels that may be the source of an oil spill to develop plans for responding to an oil spill and to acquire or have available equipment necessary to respond to a reasonably foreseeable oil spill. This act also requires owners and operators of "offshore facilities" to establish $150 million in financial responsibility to cover environmental cleanup and restoration costs likely to be incurred in connection with an oil spill. Proposals are under consideration that could amend OPA to define "offshore facilities" to include all oil and natural gas facilities that have the potential to affect "waters of the United States." The term "waters of the United States" has been broadly defined to include inland waterbodies, including wetlands, playa lakes and intermittent streams. Since we own or operate many oil and natural gas facilities that could affect "waters of the United States," we could become subject to the financial responsibility rule if it is proposed as described. Under OPA, financial responsibility could be established through insurance, guaranty, indemnity, surety bond, letter of credit, qualification as a self-insurer or a combination thereof. It is unclear whether insurance coverage will be available as a practical matter because the statute provides for direct lawsuits against insurers who provide financial responsibility coverage, and most insurers have strongly protested this requirement. We cannot predict the final form of the financial responsibility rule that may be proposed by the MMS under the act or whether pending legislation may affect it, but if such a rule were adopted and were to apply to us, we cannot assure you that we would be able to comply with the rule or as to the costs of our compliance. The Federal Water Pollution Control Act, also known as the Clean Water Act, and regulations promulgated thereunder, require containment of potential discharges of oil or hazardous substances and preparation of oil spill contingency plans. We believe that we have adequate procedures that address containment of potential discharges and spill contingency planning. The U.S. Environmental Protection Agency, or EPA, has recently increased its efforts to enforce compliance with spill containment and contingency planning requirements. The failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions. 67 72 Required Environmental Impact Statements About one-third of our acreage in the Powder River Basin is U.S. federal land and therefore subject to the environmental impact statement, or EIS, process under the National Environmental Policy Act. In addition, Montana has its own EIS process applicable to non-federal lands. The EIS for the Wyoming portion of the Powder River Basin federal lands was completed in the fall of 1999, but is in the process of being supplemented to support a substantially larger number of wells. The Montana EIS process, which is being coordinated between the BLM and Montana authorities, is just getting under way. We cannot assure you that the EIS process, once completed, will support all potential coal bed methane production well prospects. Moreover, public opposition to new drilling may cause relevant state or federal authorities to impose production limits or other permit restrictions. Currently, the Northern Plains Resource Council, Inc. has challenged the ongoing permitting of coal bed methane wells by the Montana Board of Oil and Gas Conservation without completion of any site-specific or programmatic environmental assessment, or EIS, addressing coal bed methane development in Montana. We have moved to intervene based upon our oil and gas leasehold interests within the area affected by the lawsuit. Some of these leases contain drilling date obligations that could either expire or trigger additional payment obligations if the wells cannot be permitted and drilled within the specified time frames. A settlement agreement has been submitted to the deciding court that would allow for some drilling to proceed while an EIS is being conducted. However, in the event that additional studies are required, this litigation could negatively impact our future development activity in Montana. Any delays, limitations or denials with respect to environmental or other approvals necessary for us to develop our acreage in the Powder River Basin could adversely affect our financial condition or results of operations. Liabilities and Obligations Relating to Remediation and Cleanup The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as the Superfund law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under the Superfund law, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Most states have comparable strict liability programs to address environmental contamination. We have been named a potentially responsible party for the Casmalia Disposal Superfund Site in Santa Barbara, California. We have been grouped, along with other viable companies, into the second tier generator category by EPA. EPA is seeking a total of $75 million for the pending phase of cleanup from the second-tier generators as a whole. Based on our relative position with respect to other companies in this category, we anticipate that our share of the cost of this phase of the cleanup will not be material. We cannot estimate at this time the total cleanup costs, or our resulting share, for this site. In California, the California Department of Toxic Substances Control has alleged that we are one of numerous companies that have contributed to contamination at a disposal site known as the EPC Eastside Landfill located near Bakersfield, California. The state alleges that the companies generated and shipped hazardous waste materials to the site and that releases from the site have contaminated soil and groundwater at and in the vicinity of the site. We have been placed into the second tier of potentially liable parties. We are unable to estimate at this time the total cleanup costs for this site, or our proportional share of them. With respect to our former operations in Michigan, we are engaged in, or are potentially secondarily responsible for, certain remediation activities at our formerly operated sites. We sold our Michigan 68 73 properties, with the exception of one site, in the early part of 2000 to Quicksilver Resources Inc., which has agreed to assume the liabilities and obligations associated with the continued remediation of these sites. We continue to own one site, and currently are conducting remediation at this site. Despite the fact that these sites have been sold, and Quicksilver has agreed to contractually to assume the liabilities and obligations, we continue to hold the permits for operations at the sites until the Michigan Department of Environmental Quality approves our applications for permit transfers. Until the permits have been transferred, there can be no assurance that we may not be held liable for environmental liabilities associated with these sites. Based upon our current understanding of remedial obligations at the sites discussed above, and taking into account the total estimated cost of cleanup, preliminary determinations of our allocated share, and the viability of other potentially responsible parties, we would not expect remedial costs for these matters to be material. Non-U.S. Operations Our international exploration, development and production activities are also generally subject to environmental controls which, although often not as precisely expressed by statute or regulation as those in the U.S., we view as generally establishing standards comparable to those in the U.S. Most of our international projects involve complex contractual relationships with the host government, and the sources of environmental regulation applicable to our international projects are often contractual rather than statutory or regulatory. Host governments generally require projects within their jurisdiction to employ technologically advanced methods for preventing, monitoring and remediating environmental disturbances and discharges. During the preparation of plans of development, the project operator is often required to prepare a comprehensive environmental management plan and to submit emergency preparedness and discharge clean-up contingency procedures. We may also be asked to comply with, and in some cases have committed to comply with, voluntary international standards developed by non-governmental entities, such as those promulgated by the International Standards Organization and the World Bank, in connection with obtaining financing for our operations. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse effect on us. Of course, the effect of new, or more stringent, regulations on our operations is not possible to predict. OPERATIONAL RISKS AND INSURANCE The oil and natural gas business involves certain operating hazards, any of which could result in substantial losses, including: - well blowouts; - cratering; - explosions; - uncontrollable flows of oil, natural gas or well fluids; - fires; - formations with abnormal pressures; - pollution; - releases of toxic gas; and - other environmental hazards and risks. Our offshore operations also are subject to the additional hazards of marine operations, such as severe weather, capsizing and collision. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damages and suspension of 69 74 operations. The availability of a ready market for our oil and natural gas production also depends on the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines, shipping, trucking and terminal facilities. In addition, we may be legally responsible for environmental damages caused by previous owners of property which we purchase or lease. As a result, we could incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks and losses. We currently maintain coverage with respect to general liability, commercial property, workers' compensation, automotive liability and electronic equipment. We also maintain insurance against political risk with respect to some, but not all, of our properties, and with respect to a portion, but not all, of our invested capital. With respect to the methanol plant, we have obtained operating insurance coverage which is limited to a monetary amount and has exclusions. The coverage and proceeds of our insurance may not be adequate to cover the plant's lost revenues or increased expenses in the event of a significant operation problem. We also maintain an umbrella liability policy and operator's extra expense policies. All of our insurance is subject to normal deductible levels. Among other things, coverage is not obtainable for various types of environmental hazards. Insurance covering the risk of contamination is hard to obtain, costly and very restrictive. It is generally limited to sudden, accidental events that must be reported in a very limited period of time after occurrence to the insurer. The occurrence of a significant adverse event, the risks of which are not fully covered by insurance, could have a material adverse effect on our financial condition or results of operation. Moreover, we cannot assure you that our insurance will be adequate to cover any losses or exposure to liability or that we will be able to maintain adequate insurance in the future at rates we consider reasonable. TAX MATTERS Dual Consolidated Losses Our subsidiaries own assets located in various foreign countries that have given rise to tax losses for U.S. federal income tax purposes. These losses have been utilized to offset taxable income of current or former domestic affiliates of our subsidiaries. These losses have been the subject of an annual protective election permitted under U.S. tax law. The election permits deduction of these losses for U.S. tax purposes under certain conditions. Among the conditions are that these losses may not be used to offset taxable income for foreign tax purposes, and that the taxpayer must agree that certain future events, or triggering events, would cause the recapture of the losses. These losses are referred to as dual consolidated losses, or DCLs. A triggering event would occur, for example, on the sale of the underlying assets or of the stock of an entity directly or indirectly holding these assets. Upon a triggering event, the affiliated group of corporations which utilized the losses on its consolidated U.S. federal income tax return must include an amount equal to the losses in its taxable income and in addition pay an interest rate charge on the resulting tax. In cases in which the relevant affiliated group is CMS Energy, we are primarily and/or secondarily liable for the tax liabilities associated with the recapture. We estimate that our total current DCL exposure in these regards is $71.0 million. In other cases in which the relevant consolidated group is a group now unrelated to CMS Energy or to us, for example, we remain indirectly liable for recapture of DCLs under indemnity agreements. We estimate that our total current DCL exposure in these regards is $56.0 million. Absent a closing agreement with the Internal Revenue Service, or IRS, this offering will constitute a triggering event. We and CMS Energy expect to enter into a closing agreement with the IRS which will prevent the transaction from resulting in recapture of DCLs. We and CMS Energy have agreed that in the event a closing agreement is not reached as to this offering notwithstanding our cooperation, then CMS Energy will indemnify us for the recapture. We have also agreed to an indemnification arrangement in the event of future triggering events. Under this arrangement, we will be responsible for the recapture of 70 75 any DCLs from a post-deconsolidation triggering event whether directly or under indemnity agreements with other parties. However, we believe that the triggering events generally are within our control and thus we do not anticipate that the DCLs will have to be recaptured. Nonetheless, we cannot assure you that this will be the case. Moreover, we have two separate DCL-related exposures that are not within our control. Under an agreement with BP America, Inc., we remain secondarily liable to BP America if (1) Nuevo Energy Corporation, an unrelated company, takes actions that cause DCL recapture, (2) Nuevo fails to pay the tax and interest due with respect to that recapture, (3) BP America is required by the IRS to honor its agreement to be jointly and severally liable with respect to Nuevo's DCL recapture and (4) Nuevo fails to make required indemnity payments to BP America. While we believe this series of events is unlikely, our estimate of our current exposure if these events would occur is $44.5 million plus interest. Under an agreement with Shell Petroleum Inc., we remain secondarily liable to Shell if (1) Comeco Petroleum, Inc., an unrelated company, takes actions that cause DCL recapture, (2) Comeco fails to pay the tax and interest due with respect to that recapture, (3) Shell is required by the IRS to honor its agreement to be jointly and severally liable with respect to Comeco's DCL recapture and (4) Pine Resources, an unrelated company to which our Comeco shares were sold in 1997, fails to indemnify us under an agreement reached in connection with the sale of those shares. While we believe this series of events is unlikely, our estimate of our current exposure if these events would occur is $11.5 million plus interest. International Operations We operate some of our international oil and natural gas businesses though direct and indirect wholly-owned U.S. subsidiaries which operate outside the U.S. The income or loss from these subsidiaries is taxable or deductible, as the case may be, for U.S. federal income tax purposes on a current basis. Our operations outside the U.S. may be subject to foreign income taxes as well. The U.S. federal income tax law allows a credit for foreign income taxes on income that is subject to both foreign and U.S. income taxes, thereby avoiding a double tax on foreign source income. However, substantial losses from foreign operations were utilized in past years to offset other income. As a result, special rules, including the "overall foreign loss" and the "foreign oil and gas extraction income" provisions, affect the general operation of the credit. The credit, as so affected, will operate in a manner that may subject our future foreign income to tax at a combined foreign and U.S. income tax rate significantly higher than the rate applicable to corporations that conduct only domestic operations. In addition, we conduct many of our operations outside the U.S. through non-U.S. entities. We believe that income from these entities will not be subject to U.S. income taxes until repatriated to the U.S. through dividends. Nonetheless, because of the operation of the foreign tax credit referred to above, the combined foreign and U.S. tax rate on income generated by these foreign affiliates and repatriated to the U.S. may exceed the generally applicable tax rate on corporations which conduct only domestic operations. In addition, any losses that these entities, or the other foreign entities owned by us, realize will not be currently deductible for U.S. federal income tax purposes. Deferred Taxes Under U.S. generally accepted accounting principles, a deferred tax liability is not recognized for certain temporary differences unless it becomes apparent that these differences will reverse in the foreseeable future. One difference is the excess of the earnings for financial reporting purposes over the amounts subjected to U.S. income tax with respect to an investment in a foreign subsidiary that is essentially permanent in duration. Through the end of 2000, we estimate that we have $91.0 million in earnings for which no U.S. taxes have been provided in our financial statements. Should these funds actually be repatriated or a decision be made not to indefinitely reinvest these funds offshore, then approximately an additional $32.0 million in U.S. taxes would need to be charged against earnings. 71 76 Tax Sharing and Tax Separation Agreements For information concerning our tax sharing and tax separation agreements with CMS Energy, see "Relationship and Certain Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Tax Sharing and Tax Separation Agreements." LEGAL PROCEEDINGS In 1998, our former subsidiary, Terra Energy Ltd., filed a lawsuit captioned Terra Energy Ltd. v. Star Energy, Inc., et al., Case No. 98-7490-CK, in the 13th Judicial Circuit Court in Antrim County, Michigan to collect approximately $294,000 of unpaid costs incurred in connection with the North Kitchen Farms and South Kitchen Farms projects. Terra claimed that the defendants breached agreements to pay a percentage of the costs incurred in developing these projects. On March 19, 1999, one of the defendants in the above-referenced matter filed a lawsuit against Terra in a case captioned White Pine Enterprises, L.L.C. v. Terra Energy Ltd., Case No. 99-7582-CK, in the same court, alleging that Terra breached a number of implied and express covenants as operator of the Kitchen Farms projects. In April 1999, these two lawsuits were consolidated into Terra Energy Ltd. Plaintiff and Counterdefendant v. White Pine Enterprises, L.L.C. and Star Energy, Inc., Defendants and Counterplaintiffs, Case No. 99-7582-CK. Counterplaintiffs claimed damages in the amount of $4.7 million. A mediation panel awarded counterplaintiffs damages of $225,000. Counterplaintiffs refused to accept the mediation award. In June 2000, a jury trial was held which resulted in a verdict against Terra in the amount of $7.6 million. We have agreed to indemnify the purchaser of Terra for liability resulting from this action. Terra has filed a notice of appeal. We believe that there are meritorious grounds on which the verdict in this lawsuit should be overturned or significantly reduced, and Terra intends vigorously to prosecute these grounds. We cannot predict the ultimate resolution of these matters, but we believe the resulting liabilities, if any, will not have a material adverse effect upon our financial position or results of operations or cash flows. We are named defendant in various other unrelated lawsuits and are a party in governmental proceedings from time to time arising in the ordinary course of business. While the outcome of these lawsuits and other proceedings against us cannot be predicted with certainty, management does not currently believe that these matters will have a material adverse effect on our financial condition or results of operations. OFFICES Our principal executive offices are located at 1021 Main Street, Suite 2800, Houston, Texas 77002-6606 in approximately 107,680 square feet of leased space. We also maintain leased district offices in Midland, Texas; Denver, Colorado; and Gillette, Wyoming; and international offices in Douala, Cameroon; Bogota, Colombia; Pointe Noire, the Congo; Malabo, Equatorial Guinea; and Tunis, Tunisia. All offices are managed by professional geologists or petroleum engineers. Replacement of any of our offices would not result in material expenditures and alternative locations to its leased space are anticipated to be readily available. EMPLOYEES As of September 30, 2000, we had 185 employees. We believe that our relationships with our employees are satisfactory. None of our employees is covered by a collective bargaining agreement. From time to time, we engage independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well-site surveillance, permitting and environmental assessment. Independent contractors often perform field and on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing. 72 77 MANAGEMENT EXECUTIVE OFFICERS AND DIRECTORS The following table sets forth the names, ages and positions of our executive officers and directors as of November 20, 2000. Our directors will be elected annually at each annual meeting of shareholders. Upon completion of this offering, we will add three independent directors who are unaffiliated with us or CMS Energy to our board.

Set forth below is certain biographical information relating to each of our executive officers and directors. Bradley W. Fischer. Mr. Fischer is our President and Chief Executive Officer. He earned a Bachelor of Science degree in Mechanical Engineering from the University of Nebraska in 1972 and completed the Program for Management Development at Harvard Graduate School of Business in 1991. Mr. Fischer has 28 years of experience in the oil industry. He has held executive management and operations assignments with Ashland Exploration, Inc., Mitchell Energy Corporation, Tenneco Oil Company and Texaco prior to joining us. He has both domestic and international operations experience, including management responsibility for Ashland's international operations. He joined us in August 1997 as Vice President -- Western Hemisphere and assumed his current position in August 1998. He is a member of the Society of Petroleum Engineers and is a registered professional engineer in the State of Colorado. William H. Stephens III. Mr. Stephens is our Executive Vice President, General Counsel and Secretary. He received an A.B. Degree with Distinction in All Subjects from Cornell University in 1971. In 1974 he received his J.D. from Cornell Law School. From 1974 through June 1980, he was engaged in the private practice of law concentrating in the oil and gas area. From June 1980 through July 1981, he was our General Attorney, in August 1981 he was promoted to the position of General Counsel and in October 1983 he assumed the position of Vice President Land and Legal. In October 1993, Mr. Stephens was promoted to the position of Senior Vice President and General Counsel and assumed his current position March 1, 1995. He was formerly a Director of the Michigan Oil and Gas Association and Chairman of its Industry Economics and Taxation Committee. He is a member of the Michigan, Ohio and Texas Bar Associations and a former Chairman of the Oil and Gas Committee of the Michigan Bar Association. Paul A. Doyle. Mr. Doyle is our Vice President -- Operations. He received a B.S. with honors in Civil Engineering from Georgia Institute of Technology in 1975. Mr. Doyle is a 25-year oil industry veteran who has held management and operations assignments with IP Petroleum, Tenneco Oil Company and Texaco prior to joining us in 1998. He joined our company in October 1998 as Vice President of Engineering and was made Vice President -- Operations in August 1999. He is a member of the Society of Petroleum Engineers and American Petroleum Institute and is a licensed professional engineer in the State of Texas. 73 78 W. Kenneth Keag. Mr. Keag is our Vice President -- Africa. He earned both his Bachelor's and Master's degrees in Mineralogy, Petrology, and Geology from Cambridge University. He began his career in 1972 as Geologist for Burmah Oil Trading Ltd. in London. He then joined Arco International Oil and Gas Company in 1981 as Senior Geologist and Geological Team Leader in Jakarta, Indonesia and was promoted to Senior Staff Geologist and Exploration Coordinator in Los Angeles in 1987. In 1989, he was named New Opportunities Director for ARCO in Plano, Texas and Resident Manager of ARCO Oriente Inc., Ecuador in 1991. He joined Premier Oil in London in 1996 as General Manager of Emerging Business and served as Vice President, Exploration of Premier Oil Natuna Sea Ltd., in Jakarta, Indonesia from 1998 to January 2000. On February 23, 2000, he assumed his current position as Vice President -- Africa and resides in Malabo, Equatorial Guinea. He is a Fellow of the Geological Society of London and active member of the American Association of Petroleum Geologists, the Petroleum Exploration Society of Great Britain, and Geological Society of Glasgow. Robert C. Olson. Mr. Olson is our Vice President -- Exploration. He received both a Bachelor of Science and Master of Science in Geology from San Jose State University in 1966 and 1970, respectively. During the period from 1966 through 1970, he also worked for the United States Geological Survey on Regional Potential Field Studies of Alaska and California. He has more than 30 years of worldwide petroleum exploration and development experience. From 1970 to 1974, he was a geophysicist with Humble Oil/Exxon USA concentrating on oil and gas exploration in Alaska, California and the Gulf of Mexico. From 1974 through 1996, he was with ARCO International Oil and Gas Company in various positions of increasing responsibility including Chief Geophysicist for ARCO's North Sea ventures and Exploration Manager of Europe, Africa and Latin America. In 1996 and 1997, he was Exploration Manager for VANCO Energy charged with Deep Water West Africa exploration and Netherlands marginal field development projects. In July 1997, he assumed his current position as Vice President -- Exploration. He is an active member of the American Association of Petroleum Geologist, the Society of Exploration Geophysicists, the Petroleum Exploration Society of Great Britain, the European Association of Geoscientists and Engineers, and the Geological Society of Houston. Mark E. Stirl. Mr. Stirl is our Vice President -- Controller. He received a BSBA degree in 1977 in Accounting and a Master of Business Administration degree in Finance in 1983, both from the University of Houston. From 1977 through mid-1980, he was engaged in public accounting concentrating in auditing and consulting. He joined us as Controller in March 1997, after serving the previous 17 years with Sonat Exploration Company in Houston in various accounting and financial functions, including the last seven years as Controller. In May 1998, he was promoted to his present position of Vice President -- Controller. He is a member of the Petroleum Accountants Society of Houston, the Houston Chapter of the Texas Society of Certified Public Accountants, the Texas Society of Certified Public Accountants and the American Institute of Certified Public Accountants. Victor J. Fryling. Mr. Fryling is the Chairman of our board of directors and has served as a director since 1987. Mr. Fryling has been Chief Operating Officer of CMS Energy since January 1996 and President of CMS Energy since January 1992. He has been Vice Chairman of Consumers Energy Company, a subsidiary of CMS Energy, since January 1992 and President of Consumers since August 1997. He has been a director of CMS Energy and Consumers since 1990. Mr. Fryling is currently a director and has been President and Chief Executive Officer of CMS Enterprises since May 1995. William T. McCormick, Jr. Mr. McCormick has been a director of ours since 1985. From December 1985 to February 1992, he served as the Chairman of our board of directors. Mr. McCormick has been the Chairman of the board of directors and Chief Executive Officer of CMS Energy since December 1987, the Chairman of the board of directors of Consumers since November 1985 and the Chairman of the board of directors of CMS Enterprises since May 1995. In addition, Mr. McCormick serves on the boards of directors of Bank One Corporation, Rockwell International Corporation and Schlumberger Ltd. He is also a director of the Edison Electric Institute and the National Petroleum Council. 74 79 Alan M. Wright. Mr. Wright has served as a director of ours since 1993. Mr. Wright has been Senior Vice President and Chief Financial Officer of CMS Energy since January 1992. He has been Senior Vice President and Chief Financial Officer of Consumers since January 1992. In addition, Mr. Wright has been Senior Vice President and Chief Financial Officer of CMS Enterprises since May 1998. COMMITTEES After this offering, our board of directors will establish four standing committees: an audit committee, a compensation committee, a nominating committee and an executive committee. Currently, the functions of these committees are being performed by the board of directors. Audit Committee The audit committee will recommend the employment of our independent auditors and review with management and the independent auditors our financial statements, basic accounting and financial policies and practices, audit scope and competency of control personnel. After the offering is completed, we will appoint three directors to our audit committee. Each member of the audit committee will be an "independent director" within the meaning of the rules of The New York Stock Exchange, Inc. Compensation Committee The compensation committee will review and recommend to the board of directors the compensation and promotion of our officers, the terms of any proposed employee benefit arrangements and the making of awards under these arrangements. The compensation committee will be appointed after the offering is completed and will consist of at least two members who will be "non-employee directors" within the meaning of Rule 16b-3 under the Securities Exchange Act of 1934, as amended, and "outside directors" within the meaning of Section 162(m) of the Internal Revenue Code of 1986, as amended. Nominating Committee The nominating committee will review and recommend to the board of directors modifications to director tenure policy and board size and compensation and will aid in seeking out and attracting qualified board candidates. The nominating committee will be comprised of four directors, at least two of whom are not officers of our company or other CMS Energy affiliates. Executive Committee The executive committee will exercise the power and authority of the board of directors as may be necessary during the intervals between board meetings, subject to limitations as are provided by law or resolution of the board. The executive committee will be comprised of three or four directors, at least one of whom is not an officer of our company or other CMS Energy affiliates. DIRECTOR COMPENSATION We expect that each director who is not an employee of our company or other CMS Energy affiliates will receive an annual retainer fee of $20,000 and a fee of $2,000 for each board meeting attended. In addition, we expect that, at the time of election to our board, each director who is not an employee of our company or other CMS Energy affiliates will be granted 5,000 restricted shares of our common stock, which will vest at the rate of 1,000 shares at the time of the annual meeting of shareholders in each year he or she continues to serve as a director. Directors who are employees of our company or other CMS Energy affiliates will not receive additional compensation for serving on our board. 75 80 EXECUTIVE COMPENSATION Effective with the adoption of the stock option plan described below, compensation for the executive officers will consist of a base salary, which is intended to be competitive with amounts paid to executives with equivalent positions at other oil and gas exploration and development companies of comparable size, and substantial annual and long-term incentive compensation closely tied to our success in achieving stock appreciation and other performance goals. Annual incentive (bonus) compensation payments are based on our success in meeting financial and operating goals as outlined below. In addition, individual performance goals are established for each executive for specific financial, operating and management achievements. The last element of executive compensation is expected to be long-term incentive awards in the form of stock option awards under our stock option plan as described below. The following table sets forth compensation information for our Chief Executive Officer and four other executive officers who, based on salary and bonus compensation, were our most highly compensated officers for the fiscal year ended December 31, 1999. Together, these five persons are referred to as our "named executive officers." All information set forth in the table reflects compensation earned by these individuals for services during the fiscal year ended December 31, 1999. SUMMARY COMPENSATION TABLE

--------------- (1) Shares of CMS Energy common stock. (2) Certain awards of restricted stock which would have vested in 1999 failed to achieve specified performance objectives for the relevant period. (3) CMS Energy matching contributions to defined contribution plans. 76 81 The following table sets forth information about grants of CMS Energy stock options to the named executive officers during the fiscal year ended December 31, 1999. OPTION GRANTS IN LAST FISCAL YEAR

--------------- (1) The present value is based on the Black-Scholes Model, a mathematical formula used to value options traded on securities exchanges. The model utilizes a number of assumptions, including the exercise price, the underlying stock's volatility of 16.81% using weekly closing prices for a four and one-half year period prior to grant date, the dividend rate of $0.365 per quarter with 5% annual dividend growth, the term of the option and the level of interest rates at 5.65% (equivalent to the rate of four-year Treasury Notes). However, the model does not take into account a significant feature of options granted to employees under CMS Energy's plans, the non-transferability of options awarded. The following table sets forth information concerning each exercise of stock options to purchase CMS Energy common stock by the named executive officers during the fiscal year ended December 31, 1999 and the number and value of unexercised options outstanding on December 31, 1999. AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES

The following table sets forth information regarding long-term incentive plan awards granted by CMS Energy to the named executive officers in the fiscal year ended December 31, 1999. 77 82 LONG-TERM INCENTIVE PLANS -- AWARDS IN LAST FISCAL YEAR

EXECUTIVE INCENTIVE COMPENSATION PLAN Our current annual executive incentive compensation plan provides our officers and selected key employees cash bonus payments based on the achievement of certain performance objectives established by the organization and compensation committee of CMS Energy's board of directors. The specified performance objectives are based on a combination of net income of CMS Energy and pre-tax operating income, production levels and finding costs of our company. After completion of this offering, we expect that this plan will provide cash bonus payments for participants based on our achievement of annual performance objectives established by the compensation committee of our board. Cash awards under the plan will be based generally on a percentage of the participant's salary, subject to a maximum award of 135% if 120% of the performance goal is achieved. Our board of directors will have the ability to amend, suspend or terminate the executive incentive compensation plan, subject to any requirement of shareholder approval required by applicable law. STOCK OPTION PLAN In connection with this offering, our board of directors will adopt a stock option plan. The objective of the stock option plan is to link the financial interests of our executive officers and other key employees directly with those of our shareholders. The stock option plan will make available stock options for executive officers (currently six individuals) and other key employees. The aggregate number of shares of common stock which may be issued pursuant to awards granted under the stock option plan may not exceed 5% of the outstanding shares of our common stock, and the maximum number of shares of common stock covered by awards granted to any one individual in any one calendar year is 200,000. After the offering is completed, the stock option plan will be administered by the compensation committee, which will have final authority to determine the persons to whom awards shall be granted, to determine the types of awards and the number of shares covered by awards, to determine the terms, conditions and other provisions of each award and to adopt rules and regulations for carrying out the stock option plan. 78 83 We expect to grant to our executive officers, at the time of this offering, options to purchase shares of our common stock as follows:

Each of these options is expected to have an exercise price equal to the initial public offering price of the common stock in this offering and to have a ten-year term. PENSION PLAN AND SERP TABLE We are a participating employer in the pension plan for employees of CMS Energy, which is a noncontributory defined benefit pension plan intended to qualify under Section 401(a) of the Internal Revenue Code. We are also a participating employer in the supplemental executive retirement plan for employees of CMS Energy. The supplemental executive retirement plan for employees of CMS Energy is a non-qualified plan under the Internal Revenue Code providing supplemental retirement income for our officers and selected executives, based on their years of service and final pay, as defined in the supplemental executive retirement plan. The following table shows the aggregate annual pension benefits at normal retirement presented on a straight life annuity basis under the pension plan and supplemental executive retirement plan (offset by a portion of Social Security benefits).

Regular, straight-time salary as shown in the summary compensation table during the five years of highest earnings is used in computing benefits under the pension plan. In addition, bonuses under the executive incentive compensation plan as shown in the summary compensation table during the five years of highest earnings are used in computing benefits under the supplemental executive retirement plan. As of December 31, 1999, the estimated years of service for each named executive officer are: Mr. Fischer, 4.98 years; Mr. Stephens, 29.72 years; Mr. Olson, 5.13 years; Mr. Doyle, 2.55 years; and Mr. Stirl, 5.99 years. CHANGE OF CONTROL SEVERANCE AGREEMENTS We have entered into change of control severance agreements with Messrs. Fischer, Stephens, Stirl, Olson, Doyle and Keag which guarantee specific payments and benefits upon termination of employment or an adverse change in responsibilities following a "change of control," as defined in the agreement. These agreements provide that if, after a change of control, there is an adverse change in the individual's responsibilities or the individual is involuntarily terminated other than for "cause," as defined in the agreement, then the individual will be entitled to a lump sum payment equal to three times his annual cash compensation, in the case of Messrs. Fischer and Stephens, or two times his annual cash compensation, in the case of Messrs. Stirl, Olson, Doyle and Keag. In addition, the agreements we have entered into with Messrs. Fischer and Stephens provide that the individual will be entitled to a lump sum payment equal to his annual cash compensation if the individual is involuntarily terminated by us, other than for cause, prior to a change of control. 79 84 A "change of control" is defined in the change of control severance agreements as occurring if: - a change of control of our company takes place that would be required to be reported in a current report on form 8-K filed with the SEC, whether or not we are then subject to those reporting requirements; - a person or group (1) acquires more than 30% of our then outstanding voting securities and (2) has combined voting power of our then outstanding voting securities equal to or exceeding the combined voting power of CMS Energy; - the incumbent directors or their permitted successors cease to constitute a majority of our board of directors; - within a three-year period, there is a sale of 50% or more of our assets, as determined on a book value or market value basis; or - a bidder files a tender offer statement with the SEC relating to our company. 80 85 OWNERSHIP OF CAPITAL STOCK CMS Enterprises, 330 Town Center Drive, Suite 1100, Dearborn, MI 48126, currently beneficially owns all of our outstanding common stock. Following completion of this offering, CMS Enterprises will beneficially own shares of our common stock, representing % of our outstanding common stock. CMS Enterprises has sole voting and investment power with respect to all shares beneficially owned by it. CMS Energy owns all of the outstanding common stock, and Consumers Energy Company, or Consumers, owns all of the outstanding preferred stock, of CMS Enterprises. CMS Energy owns all of the outstanding common stock of Consumers. As of November 15, 2000, 120,908,799 shares of CMS Energy common stock and 125,000 shares of CMS Energy preferred stock were outstanding. CMS Energy's common stock is listed on The New York Stock Exchange. Holders of CMS Energy common stock are entitled to one non-cumulative vote per share on each matter voted upon by the shareholders of CMS Energy. The following table sets forth certain information with respect to the beneficial ownership of the common stock of CMS Energy as of November 15, 2000 by: - each of our directors and executive officers; and - all of our directors and executive officers as a group. Shares shown as beneficially owned include (1) shares to which a person has or shares voting power and/or investment power and (2) shares and share equivalents represented by interests in the CMS Energy Employees' Savings and Incentive Plan, the CMS Energy Deferred Salary Savings Plan, the CMS Energy Performance Incentive Stock Plan and the CMS Energy Directors' Deferred Compensation Plan.

--------------- * Less than 1%. (1) Includes option exercisable within the next 60 days as follows: Mr. Fischer, 26,000 shares; Mr. Stephens, 31,000 shares; Mr. Doyle, 16,000 shares; Mr. Olson, 28,000 shares; Mr. Stirl, 20,000 shares; Mr. McCormick, 549,000 shares; Mr. Fryling, 322,000 shares; Mr. Wright, 90,000 shares; and all directors and executive officers as a group, 1,082,000 shares. 81 86 RELATIONSHIP AND CERTAIN TRANSACTIONS WITH CMS ENERGY AND AFFILIATES VOTING CONTROL Upon completion of this offering, CMS Enterprises will own approximately % ( % if the underwriters exercise their over-allotment option in full) of our issued and outstanding common stock. As a result, CMS Enterprises and CMS Energy, indirectly by virtue of its control of CMS Enterprises, will be able to elect, or have a significant influence over the election of, all of the members of our board of directors and have a significant influence over our affairs and policies, including our exploration, development, capital, operating and acquisition expenditure plans. Following completion of this offering and the election of three independent directors, our board of directors will be composed of seven members, three of whom are directors or current or former officers of CMS Energy or CMS Enterprises. CONTRACTUAL ARRANGEMENTS We have entered or will enter into a number of agreements with CMS Energy or its subsidiaries for the purpose of defining our ongoing relationship following completion of this offering. These agreements were or will be developed in connection with this offering while we are a wholly-owned subsidiary of CMS Enterprises and, therefore, were and will not be the result of arm's-length negotiation between independent parties. As a result, there can be no assurance that these agreements or the transactions provided for in these agreements have been or will be effected on terms at least as favorable to us as could have been from unaffiliated third parties. Services Agreements Prior to the completion of this offering, we expect to enter into various agreements with each of CMS Energy, CMS Enterprises and Consumers pursuant to which those entities will make or cause to be made available to us, from time to time, management and consulting services, including administrative, clerical, managerial, professional and/or technical services as we may from time to time agree. In addition, we expect to enter into various agreements with each of CMS Enterprises, CMS MST and Panhandle Eastern Pipe Line Company pursuant to which we will make or cause to be made available to those entities, from time to time, information systems and technology support, facilities management, leasing of space and travel management services as we may from time to time agree. In the past, we have entered into various agreements with CMS Energy, CMS Enterprises, CMS MST and Consumers pursuant to which those entities have provided us, from time to time, with management and consulting services, including administrative, clerical, managerial, professional and/or technical services. For services provided under those agreements, we have paid the following amounts for the years ended December 31, 1997, 1998 and 1999: - to CMS Energy, $0.7 million, $2.1 million and $2.0 million, respectively; - to CMS Enterprises, $0.9 million, $1.4 million and $0.7 million, respectively; - to CMS MST, $0.2 million, $0.4 million and $0.6 million, respectively; and - to Consumers, $0.6 million, $0.6 million and $0.6 million, respectively. Registration Rights Agreement Prior to the completion of this offering, we expect to enter into a registration rights agreement with CMS Enterprises under which we will agree, upon the request of CMS Enterprises, to file one or more registration statements under the Securities Act of 1933, as amended, or take other appropriate action under the laws of foreign jurisdictions in order to permit CMS Enterprises to offer and sell, domestically or abroad, the shares of our common stock or other securities that it holds. CMS Enterprises will pay all costs relating to the exercise of its registration rights, as well as any underwriting discounts and commissions relating to any such offering, except that we will pay the fees and expenses of our 82 87 accountants and any trustees, transfer agents or other agents appointed in connection with an offering under the registration rights agreement. There is no limitation on the number or frequency of requests that CMS Enterprises may make to register its shares, except that we will not be required to comply with any registration request unless, in the case of a class of equity securities, the request involves at least the lesser of: - one million shares; or - 1% of the total number of shares of any class then outstanding. We will also grant to CMS Enterprises the right, if we file a registration statement, to require us to include the securities it owns in that registration statement. We will pay all costs relating to any such registration, other than incremental costs attributable to the inclusion of securities owned by CMS Enterprises in the registration statement. CMS Enterprises will pay the fees and expenses of its counsel and all underwriting discounts and commissions with respect to the securities offered by it. We will have the right to delay any registration of securities owned by CMS Enterprises for a period of up to 90 days if, in our judgment, that registration would materially adversely affect any underwritten offering then being conducted or about to be conducted by us. In addition, we will have the right to exclude from any registration securities owned by CMS Enterprises which, in the judgment of the managing underwriters, would materially adversely affect our offering of securities. We will agree to indemnify CMS Enterprises, its officers and directors, each underwriter, if any, and each person who controls CMS Enterprises or any underwriter against certain liabilities, including liabilities under the Securities Act, in connection with any registration under the registration rights agreement. CMS Enterprises may transfer any of its rights under the registration rights agreement to non-affiliates. Tax Sharing and Tax Separation Agreements Until this offering is completed, we will be a member of the CMS Energy affiliated group of corporations that files its U.S. federal income tax returns on a consolidated basis. As a member of the CMS Energy affiliated group, we are subject to a tax sharing agreement dated as of January 1, 1994. This agreement governs our current relationship with CMS Energy on various tax matters. Upon completion of this offering, we will cease to be a member of the CMS Energy affiliated group and will become our own affiliated group for U.S. federal income tax purposes. In recognition of this fact, we and CMS Energy have entered into a tax separation agreement. This agreement, which becomes effective upon the date of completion of this offering, governs tax matters between the parties. In general, it provides that: - the current tax sharing agreement to which we are subject will be terminated and we will have no further rights or obligations under it; - within sixty days of the date of completion of this offering we will make an estimated tax payment to CMS Energy to cover taxes covered by combined returns with CMS Energy for periods ending prior to or on the day of completion; and - thereafter, we will be responsible only for (1) federal income taxes relating to periods beginning after the completion of this offering; (2) state and local income taxes reportable on a combined return relating to periods beginning after completion of this offering; (3) all state, local and foreign taxes as initially reported on all separate returns for years ending on or before December 31, 2000 (with CMS Energy liable for any taxes arising from audit adjustments or amendments relating to those periods); and (4) all other state, local, and foreign taxes relating to taxable years ending after December 31, 2000. 83 88 The agreement also generally provides that CMS Energy will be responsible for any taxes resulting from the completion of this offering. Finally, under the tax separation agreement and pursuant to applicable tax law, we will be entitled to potential tax benefits, including minimum tax credit carryovers. These potential tax benefits will only be of use to us if we generate sufficient taxable income. A closing agreement between CMS Energy, the Internal Revenue Service and us will be required upon our leaving the CMS Energy affiliated group. This closing agreement avoids dual consolidated loss recapture, and specifies that CMS Energy and we will be jointly and severally liable to the Internal Revenue Service in the event of an unremedied future dual consolidated loss triggering event. In connection with the closing agreement described above, an indemnification agreement will become effective between CMS Energy and us upon our leaving the CMS Energy affiliated group. Although the closing agreement specifies joint and several liability between CMS Energy and us in favor of the Internal Revenue Service, the indemnification agreement generally places the economic burden on us in the event of a dual consolidated loss triggering event occurring after deconsolidation. BP Amoco Indemnification Agreement and Related CMS Tax Indemnity Agreement In connection with our acquisition of CMS Oil and Gas (International) Company in 1995, we, CMS Energy and our subsidiaries have agreed to be jointly and severally liable for CMS Oil and Gas (International) Company's obligation to indemnify BP Amoco for tax liabilities attributable to the recapture of dual consolidated losses utilized by BP Amoco for tax purposes in prior years, if a triggering event, as defined under U.S. federal income tax laws relating to dual consolidated losses, were to occur with respect to the assets or with respect to the stock of these entities or of their subsidiaries. CMS Energy has agreed to indemnify us for liability relating to recapture of our dual consolidated losses or those of any of our subsidiaries or separate units if a triggering event results from (1) any act or omission occurring prior to deconsolidation or (2) a failure to obtain a closing agreement with respect to this offering not caused by us. We have agreed to indemnify CMS Energy for the recapture of any dual consolidated losses from a post-deconsolidation triggering event unless directly caused by an action of CMS Energy other than in its capacity as our shareholder. For additional information concerning our indemnification obligations, see "Business and Properties -- Tax Matters -- Dual Consolidated Losses." Acquisition of Methanol Plant We have agreed to purchase, prior to the completion of this offering, CMS Gas Transmission's 50% interest in Atlantic Methanol Capital, which owns an indirect 90% interest in a 2,500 metric ton per day methanol production facility currently in the late stages of construction on Bioko Island in Equatorial Guinea. We will purchase this interest by issuance of a note payable to CMS Gas Transmission in the principal amount of approximately $137.0 million (which includes estimated funds necessary to complete the facility and accrued interest on the Atlantic Methanol Capital Series A-1 Notes through April 30, 2001), which will be repaid with the aggregate proceeds from this offering and our concurrent offering of senior subordinated notes. Atlantic Methanol Capital has issued $125.0 million of limited recourse indebtedness, which is secured by, among other things, a pledge of 60% of the interest we expect to acquire in the plant. Note Payable to CMS Enterprises Prior to the completion of this offering, we expect to distribute to our parent company, CMS Enterprises, a note payable in the principal amount of $39.0 million. This note will not bear interest and will become due and payable upon completion of this offering. We intend to use a portion of the aggregate net proceeds to us from this offering and our concurrent offering of senior subordinated notes to repay this note. 84 89 Oil Marketing Agreement Prior to the completion of this offering, we expect to enter into a master oil marketing agreement with CMS MST pursuant to which it will serve as the exclusive marketer of all our available domestic and international oil, including condensate and NGLs, but excluding: - oil produced in Venezuela or in any other country in which we are obligated to sell our production to a state agency or other entity designated by the state; - plant products that are marketed by a plant operator other than us; - oil produced from properties not operated by us when we have elected to have the operator market our production; and - oil production where CMS MST marketing activities would, in our reasonable, good faith judgment, cause us to breach any of our third party agreements or arrangements, unless CMS MST obtains an appropriate release from that third party. We will pay to CMS MST a fee of $0.05 per barrel for all sales for which CMS MST provides marketing services. This price will be renegotiated every two years so as to reflect the current market price for the services. If we and CMS MST are unable to agree upon a price, we will have the right to market our oil through a third party, although CMS MST will have preferential rights to match any third party terms offered to us. The oil marketing agreement will have an initial term of ten years. Gas Sales Agreements Master Gas Sales Agreement. Prior to the completion of this offering, we expect to enter into a master gas sales agreement with CMS MST pursuant to which it will purchase all of our gas that is produced in the Powder River Basin and the Freshwater Bayou Field and have a preferential right to match any third party terms offered to us to purchase any of our other natural gas produced in the U.S., Canada or Mexico. We will not, however, be committed to sell gas to CMS MST if it would violate any contract we have with a third party. The term of this agreement will be for ten years. This agreement will not apply to: - gas under any existing sales contracts between us and a third party until that contract is terminated or otherwise ceases to be in force and effect; - gas used or consumed by us or the operator for field use; or - gas attributable to interests in acreage farmed out by us to third parties. Powder River. Pursuant to the master gas sales agreement, we expect to enter into a gas sales agreement with CMS MST under which it will purchase all of our production from the Powder River Basin. Under this agreement, we will nominate monthly the firm quantity of gas to be delivered daily by us during the following month. In addition to this firm quantity, CMS MST will be obligated to purchase from us a variable quantity of gas not to exceed 20% of the total quantity nominated. The price for the firm quantity of gas will be equal to the Cheyenne Index Price for the month during which the delivery is made and the price for the variable quantity will be equal to the Gas Daily Index Price applicable to the relevant delivery points on the day the variable quantity of gas is delivered. The pricing formula will be subject to renegotiation after 180 days and annually thereafter. If, upon renegotiation we and CMS MST are unable to agree upon a pricing formula, we will have the right to sell our gas to a third party, although CMS MST will have preferential rights to match any third party terms offered to us. Freshwater Bayou. Pursuant to the master gas sales agreement, we expect to enter into a gas sales agreement with CMS MST under which it will purchase all of our gas production from the Freshwater Bayou Field in Louisiana. Under this agreement, we will nominate monthly the firm quantity of gas to be delivered daily by us during the following month. In addition to this firm quantity, CMS MST will be obligated to purchase from us a variable quantity of gas not to exceed 20% of the total quantity nominated. 85 90 The price for the firm quantity of gas will be equal to the index price for that month's gas published by "Inside FERC" for Texas Gas Zone SC and the price for the variable quantity will be equal to the Gas Daily Index Price applicable to the relevant delivery points on the day the variable quantity of gas is delivered. The pricing formula will be subject to annual renegotiation. If upon renegotiation we and CMS MST are unable to agree upon a pricing formula, we will have the right to sell our gas to a third party, although CMS MST will have preferential rights to match any third party terms offered to us. Trailblazer Pipeline Agreement To improve CMS MST's ability to take all the gas we are able to deliver from the Powder River Basin, we have agreed to guarantee recovery by CMS MST of a portion of the capacity charge which it has agreed to pay for capacity on the expanded Trailblazer pipeline system serving the Powder River area. When the expansion is complete, which is expected to occur in late 2002, CMS MST will be obligated to pay a fee for 100,000 Mcf of daily capacity calculated at the rate of $0.24 per Mcf. Under our agreement with CMS MST, we will prepay to CMS MST each month a fee of $0.048 per Mcf for 100,000 Mcf, or a total monthly payment of $144,000. CMS MST will reimburse us under a formula intended to measure the market value of Trailblazer capacity for each month. If this value, as so determined each month, exceeds $0.24 per Mcf, we will be reimbursed in full for that month's payment and we will be reimbursed 20% of the value in excess of $0.24 per Mcf. If this value is between $0.192 per Mcf and $0.24 per Mcf, we will be reimbursed the difference between this value and $0.192 per Mcf. If this value is $0.192 per Mcf or less, we will not be reimbursed that month. Gathering and Processing Agreements Master Field Services Agreement. Prior to the completion of this offering, we expect to enter into a master field services and support agreement with CMS Field Services. This agreement grants CMS Field Services first offer rights with respect to all of our oil and field gas gathering, processing, treating, compressing and certain other field service requirements as they may arise from time to time. If we are unable to reach mutual agreement with CMS Field Services on the terms for those services, we are entitled to seek offers for the services from third parties, although CMS Field Services will have preferential rights to match any third party terms offered to us. CMS Field Services will not have preferential rights, however, if these rights would violate any agreements, such as joint operating agreements, with third parties. The master field services agreement will have a term of ten years. West Texas. We have entered into a gas gathering agreement with CMS Field Services pursuant to which it will gather some of our West Texas gas production. Under this agreement, CMS Field Services has constructed gathering, compression and other facilities to receive our gas production from the area south of Midland, Texas. We pay a gathering fee sufficient to allow CMS Field Services to recover, over a five year period, operating costs and its capital invested in gathering facilities, plus a 20% pretax annual rate of return. Powder River. We have entered into two agreements with affiliates of CMS Field Services pursuant to which they provide compression and gathering services for our Powder River production. For these services, we pay a fee of either $0.74 per Mcf or $0.88 per Mcf depending on the distance between the point of production and the point of redelivery. Each of these agreements has a term of 20 years, beginning in 1999. Hedging Agreements Hedging Administrative Support, Information and Advisory Services. Prior to the completion of this offering, we expect to enter into a hedging administrative support, information and advisory services agreement with CMS MST pursuant to which it will provide to us the following services: - provision of historical and current energy market and related data (e.g., weather data); - analysis of historical and current data and development of projections for future prices; and 86 91 - identification of hedging strategies consistent with our hedging policy. We will pay to CMS MST, subject to renegotiation every two years, a fee of $4,000 per month for the base service level of 1,040 person hours per annum and $100 per person hour in excess of that base service level. This agreement will have an initial term of ten years. Hedging Brokerage Services. Prior to the completion of this offering, we also expect to enter into a hedging brokerage services agreement with CMS MST pursuant to which it will provide to us the following services: - administrative support services (e.g., contract administration, invoicing and accounting, and counterparty credit analysis) for hedging activities; - broker services (e.g., identifying and negotiating with counterparties); and - the arrangement of derivative transactions that we will enter into directly with CMS Enterprises. We expect CMS Enterprises to be the counterparty in most of our hedging transactions, provided that it accepts the competitive terms as determined by CMS MST and subject to our review. We will pay to CMS MST, subject to renegotiation every two years, a fee of $0.005 per MMBtu of gas volumes hedged and $0.05 per barrel of oil volumes hedged. This agreement will have an initial term of ten years. CONFLICTS OF INTEREST Our relationship with CMS Energy and its affiliates may give rise to conflicts of interest with respect to, among other things: - transactions and agreements between us and CMS Energy and its affiliates; - issuances of additional shares of our equity securities; and - the election of directors or the payment of dividends, if any, by us. When the interests of CMS Energy and its other subsidiaries diverge from our interests, CMS Energy may exercise its influence in favor of its own interests or the interests of another subsidiary over our interests. CMS Energy has advised us that it does not intend to engage in the exploration for or development or production of natural gas and oil, except through its indirect ownership of our common stock and except that it may engage in exploration, development and production for domestic natural gas to the extent necessary to provide natural gas feedstock or as a natural hedge for its other energy businesses. Circumstances may thus arise that would result in CMS Energy, by itself or through one of its affiliated entities, engaging in the exploration for or development or production of natural gas. Moreover, after completion of this offering and the election of three independent directors, our board of directors will consist of seven members, three of whom are directors and/or officers of CMS Energy. As the individuals affiliated with CMS Energy perform their duties to CMS Energy and to us, conflicts of interest and conflicting demands on the amount of time these individuals will have available for our affairs may arise. We cannot assure you that any of these conflicts will be resolved in our favor. From time to time, we and CMS Energy and its other subsidiaries have entered into significant transactions and agreements incident to our respective businesses, and we intend to enter into similar transactions and agreements in the future. We cannot assure you that any of these transactions or agreements have been or will be effected on, or will in the future result in our obtaining, terms at least as favorable to us as could have been obtained from unaffiliated third parties. 87 92 CERTAIN TRANSACTIONS Assignment of Midland Cogeneration Venture Gas Sale Agreement and Related Gas Purchase Hedge Agreements In April 2000, we entered into an agreement with CMS MST pursuant to which CMS MST has agreed to assume all the economic benefits and costs associated with the performance of our obligations: - to sell a minimum of 7,500 MMBtu of natural gas to Midland Cogeneration Venture Limited Partnership, or MCV, through December 31, 2006 under a contract dated May 1, 1989; - under various gas purchase agreements we had entered into to assist in meeting our obligation under the MCV gas sales agreement; and - under a hedge agreement we had entered into with Louis Dreyfus Natural Gas to purchase the economic equivalent of 10,000 MMBtu per day at fixed, escalating prices starting at $2.82 per MMBtu in 2001. Under the agreement with Louis Dreyfus, if the floating price of natural gas for a period is higher than the fixed price, the seller would pay to us the difference, and if the fixed price for a period is higher than the floating price, we would pay to the seller the difference. At September 30, 2000 the fair market value of the contract reflected a payment due to CMS MST in the amount of $6.6 million. Although CMS MST has assumed our obligations under the agreements described above, we have not been released from our obligations under them; accordingly we remain liable for all of CMS MST's obligations if CMS MST should fail to fulfill its obligation under these agreements and we will have recourse against CMS MST. CMS Notes CMS Energy Note. In August 1995, we issued a note in the principal amount of approximately $61.3 million to CMS Enterprises, which in turn assigned it to CMS Energy, in connection with the transfer of the common stock of Terra Energy Ltd. by CMS Energy to CMS Enterprises, and then by CMS Enterprises to us. In 1999, this note was amended to extend the maturity to April 15, 2009 and to suspend the interest payments until April 4, 2004. Interest will accrue and will be added to the outstanding debt balance. The note bears interest at the three-month LIBOR plus 2% per annum. Amounts outstanding under the note are expressly subordinate to borrowings under our credit facility, and we are subject to limitations on our obligation to make payments on the note in the event of default under the terms of the credit facility. As of September 30, 2000, $63.4 million of principal and interest was outstanding under the CMS Energy note. We expect to repay this note in full upon completion of this offering and our concurrent offering of senior subordinated notes. Note Receivable from Western Australia Gas Transmission. In July 2000, we loaned $32.0 million of the net proceeds we received from the sale of our Ecuador properties to Western Australia Gas Transmission Company I, an affiliate of CMS Energy. On October 9, 2000, that note became payable and Western Australia Gas Transmission paid this note by entering into an additional note with us. This additional note, dated October 10, 2000, has a principal of $32,515,200 and bears interest at a rate of 6.44% per annum, compounded daily based on a 360-day-year. The term of the note is 90 days and is scheduled to mature on January 8, 2001. We expect this note to be repaid in full by December 31, 2000. Contributions to Capital During the years ended December 31, 1998 and 1999, we received equity contributions from CMS Enterprises in the amounts of $35.0 million and $58.3 million, respectively. 88 93 Repurchase of Interests Under Employee Well Participation Program In 1996, we entered into an agreement with William H. Stephens III, our Executive Vice President, General Counsel and Secretary, pursuant to which we agreed to purchase overriding royalty interests previously owned by Mr. Stephens for cash and phantom stock units relating to CMS Energy common stock. Pursuant to the terms of the agreement, in each of the years 1997 through 2000, we paid to Mr. Stephens in cash amounts equal to $113,284, $138,890, $133,723 and $56,744, respectively, representing: - a stipulated percentage of the value of his phantom stock units at that time (including appreciation, if any, on the securities underlying the phantom stock units); and - an amount equal to any dividends paid on the securities underlying the phantom stock units at the time those dividends were paid. We currently estimate that the final payment of cash to Mr. Stephens, on or about March 1, 2001, will be in the amount of $64,550, of which $63,691 represents payment for his phantom stock units and $859 represents the amount equal to dividends on the securities underlying the phantom stock units. 89 94 DESCRIPTION OF CAPITAL STOCK The following summary description of our capital stock is qualified in its entirety by reference to our Restated Articles of Incorporation and Restated Bylaws, a copy of each of which is filed as an exhibit to the registration statement of which this prospectus is a part. Our authorized capital stock consists of 55,000,000 shares of common stock, no par value per share, and 5,000,000 shares of preferred stock, no par value per share. As of the date hereof, shares of common stock, all of which are owned by CMS Enterprises, and no shares of preferred stock are outstanding. Upon completion of the offering, shares of common stock will be outstanding, of which shares will be owned by CMS Enterprises, assuming no exercise of the underwriters' over-allotment option. We have reserved shares of common stock for issuance pursuant to our stock option plan. OUR COMMON STOCK Voting Rights. The holders of common stock are entitled to one vote per share on all matters submitted to a vote of shareholders. Holders of common stock do not have cumulative voting rights with respect to the election of directors. Generally, all matters submitted to a vote of shareholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the shares of common stock present in person or represented by proxy and entitled to vote, subject to any voting rights granted to holders of any preferred stock. After the offering, CMS Enterprises will hold approximately % of our issued and outstanding common stock, or % if the over-allotment option is exercised in full, and therefore will hold the voting power to determine all matters upon which our shareholders vote, including the election of directors. See "Relationship and Certain Transactions with CMS Energy and Affiliates." Dividends. Holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the board of directors out of funds legally available therefor. Other Rights. In the event of a liquidation, dissolution or winding up of our company, holders of common stock are entitled to share ratably in all net assets available for distribution to common shareholders. Holders of common stock have no preemptive, subscription, redemption or conversion rights. All outstanding shares of common stock, including the shares being issued in the offering, are fully paid and nonassessable. We will apply to list our common stock on The New York Stock Exchange under the symbol "CGS." OUR PREFERRED STOCK Our board of directors has the authority, without further action by shareholders, to issue up to 5,000,000 million shares of preferred stock in one or more series and to fix and determine the relative rights and preferences of the preferred stock, including, among others, dividend rights, voting rights, redemption and sinking fund provisions, liquidation preferences and conversion rights. The issuance of preferred stock, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could adversely affect the voting power of holders of our common stock and could have the effect of delaying, deferring or preventing a change in control of our company. CERTAIN PROVISIONS OF MICHIGAN CORPORATE LAW We are subject to the business combination provisions of the Michigan Business Corporation Act. In general, those provisions prohibit a publicly held Michigan corporation from engaging in various business combination transactions with any interested shareholder unless: - the business combination transaction, or the transaction in which the interested shareholder became an interested shareholder, is approved by the board of directors prior to the time the interested shareholder obtained such status; 90 95 - on or subsequent to that date, the business combination is approved by the board of directors and authorized by the affirmative vote of: - at least 90% of the votes of each class of stock entitled to be cast by the shareholders of the corporation; and - at least 66 2/3% of the votes of each class of stock entitled to be cast by the shareholders of the corporation, other than voting shares beneficially owned by the interested shareholder or its affiliates or associates; or - all of the following conditions are met: - the aggregate amount of consideration to be received by holders of common stock in the business combination is at least equal to the higher of: - the highest per share price paid by the interested shareholder for shares of common stock of the same class or series acquired by the interested shareholder within the two-year period prior to the announcement of the proposed business combination or in the transaction in which the shareholder became an interested shareholder (whichever is higher); and - the market value per share of common stock of the same class or series on the announcement date or determination date (whichever is higher); - the aggregate amount of consideration to be received by holders of shares of any class or series other than common stock is at least equal to the higher of: - the highest per share price paid by the interested shareholder for any shares of the class of stock acquired by the interested shareholder within the two-year period prior to the announcement of the proposed business combination or in the transaction in which the shareholder became an interested shareholder (whichever is higher); - the highest preferential amount per share to which holders of the class of stock are entitled in the event of liquidation, dissolution or winding-up of the corporation; and - the market value per share of the class of stock on the announcement date or determination date (whichever is higher); - the consideration to be received by holders of any class or series of stock is in cash or the same form as the interested shareholder has previously paid for shares of the same class or series of stock; and - after the shareholder has become an interested shareholder and prior to the consummation of the business combination: - all full periodic dividends on any outstanding preferred stock of the corporation shall have been paid; - the annual rate of dividends paid on any class or series of stock other than preferred stock shall not have been reduced; - the interested shareholder shall not have received the benefit of any loans, advances, guarantees or pledges provided by the corporation or its subsidiaries; and - the business combination does not occur until five years after the date the shareholder became an interested shareholder. A "business combination" is defined to include mergers, asset sales and other transactions resulting in financial benefit to a shareholder. In general, an "interested shareholder" is a person who, together with affiliates and associates, owns 10% or more of a corporation's voting stock. The statute could prohibit or delay mergers or other takeover or change in control attempts with respect to our company and, accordingly, may discourage attempts to acquire us. 91 96 LIMITATION ON PERSONAL LIABILITY OF DIRECTORS; INDEMNIFICATION PROVISIONS Our Restated Articles of Incorporation contain a provision, authorized by the Michigan Business Corporation Act, designed to eliminate the personal liability of directors for monetary damages to us or our shareholders for breach of their fiduciary duty as directors. This provision, however, does not limit the liability of any director who breached his duty of loyalty to us or our shareholders, failed to act in good faith, obtained an improper personal benefit, or paid a dividend or approved a stock repurchase or redemption that was prohibited under Michigan law. This provision will not limit or eliminate our rights or those of any shareholder to seek an injunction or any other non-monetary relief in the event of a breach of a directors' duty of care. In addition, this provision applies only to claims against a director arising out of his role as a director and does not relieve a director from liability unrelated to his fiduciary duty of care or from a violation of statutory law such as certain liabilities imposed on a director under the federal securities laws. Our Restated Articles of Incorporation and Restated Bylaws require us to indemnify all of our directors and officers to the full extent permitted by the Michigan Business Corporation Act. Under the provisions of the Michigan Business Corporation Act, any director or officer who, in his capacity as such, is made or threatened to be made a party to any suit or proceeding may be indemnified if our board determines the director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to our or our shareholders' best interests. In addition, our officers and directors and the officers and directors of our subsidiaries are covered within specified monetary limits by insurance against certain losses arising from claims made by reason of their acting as such, and our officers and directors are also indemnified against losses by reason of their being or having been directors of officers of another corporation, partnership, joint venture, trust or other enterprise at our request. TRANSFER AGENT AND REGISTRAR CMS Energy, 212 West Michigan Avenue, Jackson, MI 49201, attention: Investor Services, is the transfer agent and registrar for our common stock. SHARES ELIGIBLE FOR FUTURE SALE Upon completion of the offering, we will have outstanding shares of our common stock, assuming the underwriters' over-allotment option is not exercised. All of the shares sold in the offering will be freely tradable without restriction by persons other than our "affiliates," as that term is defined under Rule 144 under the Securities Act of 1933, as amended. Persons who may be deemed affiliates generally include individuals or entities that control, are controlled by or are under common control with us and may include our officers, directors and significant shareholders. The remaining shares of common stock that will continue to be held by CMS Enterprises after the offering will constitute "restricted securities" within the meaning of Rule 144 and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration. As described under "Relationship and Certain Transactions With CMS Energy and Affiliates," pursuant to the registration rights agreement, CMS Enterprises may cause us at any time to register all or a portion of the common stock owned by it, in which event CMS Enterprises would be able to sell those shares upon the effectiveness of that registration without regard to the provisions of Rule 144. As discussed under the heading "Underwriting," we, CMS Enterprises, CMS Energy and each of our directors and executive officers have agreed not to offer, sell, contract to sell, pledge or otherwise dispose of any shares of our common stock or any securities convertible into or exchangeable or exercisable for our common stock (other than pursuant to employee stock incentive plans existing or contemplated on the date of this prospectus and for other specified purposes), for a period of days after the date of this prospectus, without the prior written consent of Credit Suisse First Boston Corporation. Upon expiration of this period, all shares of common stock held by CMS Enterprises will have been held 92 97 for more than one year and will be available for sale in the public market, subject to compliance with the volume and other limitations of Rule 144 as described below. In general, under Rule 144 as currently in effect, beginning 90 days after the date of this prospectus, a person, or persons whose shares are aggregated, who has beneficially owned restricted shares for at least one year, including the holding period of any prior owner, other than an affiliate of ours, would be entitled to sell within any three-month period a number of shares that does not exceed the greater of: - 1% of the number of shares of common stock then outstanding, which will equal approximately shares immediately after this offering; or - the average weekly trading volume of the common stock during the four calendar weeks preceding the filing of a Form 144 with respect to the sale. Sales under Rule 144 also are subject to manner of sale provisions and notice requirements and to the availability of current public information about us. Under Rule 144(k), a person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner, other than an affiliate of ours, is entitled to sell those shares without complying with the manner of sale, public information, volume limitation or notice provisions of Rule 144. Rule 144A under the Securities Act permits resales of restricted securities under certain conditions provided that the purchaser is a "qualified institutional buyer," as defined therein, which generally refers to institutions with over $100 million invested in securities. Rule 144A allows holders of restricted securities to sell their shares to those purchasers without regard to volume or any other restrictions. We currently intend to file promptly after the completion of the offering a registration statement on Form S-8 under the Securities Act to register shares of common stock reserved for issuance under our stock option plan. Based on the number of shares we expect to reserve for issuance under the plan, that registration statement would cover up to shares issuable on exercise of options, of which options to purchase shares will have been issued effective as of the date of completion of this offering. The registration statement on Form S-8 will become effective automatically upon filing. Accordingly, subject to the exercise of those options, shares registered under that registration statement will be available for sale in the open market immediately after the expiration of the lock-up agreements described above. Prior to the offering, there has been no public trading market for our common stock. Sales of substantial amounts of common stock in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices and could impair our ability to raise capital in the future through the sale of our equity securities. 93 98 UNDERWRITING Under the terms and subject to the conditions contained in an underwriting agreement dated , 2001, we and the selling shareholder have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston Corporation is acting as representative, the following respective numbers of shares of common stock:

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated. We and/or the selling shareholder have granted to the underwriters a 30-day option to purchase on a pro rata basis up to additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock. The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $ per share. The underwriters and selling group members may allow a discount of $ per share on sales to other broker/dealers. After the initial public offering, the public offering price and concession and discount to broker/dealers may be changed by the representative. The following table summarizes the compensation and estimated expenses we and the selling shareholder will pay:

The representatives of the underwriters have informed us that they do not expect discretionary sales to exceed 5% of the shares of common stock being offered. We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act of 1933 relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any such offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston Corporation for a period of days after the date of this prospectus, except issuances pursuant to the exercise of options outstanding on the date hereof and issuances of options to our executive officers upon completion of this offering, as described in this prospectus. 94 99 CMS Enterprises, CMS Energy and each of our directors and executive officers have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or enter into a transaction which would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse First Boston Corporation for a period of days after the date of this prospectus. The underwriters have reserved for sale, at the initial public offering price, up to shares of the common stock for employees and directors of our company and CMS Energy, and members of their immediate families, who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares. We and the selling shareholder have agreed to indemnify the underwriters against liabilities under the Securities Act, or to contribute to payments that the underwriters may be required to make in that respect. We will apply to list the shares of common stock on The New York Stock Exchange under the symbol "CGS." In connection with the listing of the common stock on The New York Stock Exchange, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 2,000 beneficial owners. Prior to this offering, there has been no established public trading market for our common stock. Consequently, the initial public offering price will be determined by negotiation among us, the selling shareholder and the representative of the underwriters. Among the factors to be considered in determining the initial public offering price, in addition to prevailing market conditions, will be: - current and historical oil and natural gas prices; - current and prospective conditions in the supply and demand for oil and natural gas; - reserve and production quantities for our oil and natural gas properties; - the history of and prospects for the industry in which we operate; - the earnings multiples of publicly traded common stocks of comparable companies; - our cash flows and earnings and those of comparable companies in recent periods; and - our business potential and prospects for future cash flows and earnings. We can offer no assurances that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to this offering or that an active trading market for our common stock will develop and continue after this offering. Some of the underwriters and their affiliates have from time to time performed various investment banking and financial advisory services for CMS Energy and CMS Enterprises, for which they have received customary fees and reimbursement of their out-of-pocket expenses. These services include serving as underwriter or private placement agent in connection with various securities offerings. In connection with the offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids. - Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum. - Over-allotment involves sales by the underwriters in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position 95 100 may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing shares in the open market. - Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering. - Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions. These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time. A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters participating in this offering. The representatives may agree to allocate a number of shares to underwriters for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters that will make internet distributions on the same basis as other allocations. NOTICE TO CANADIAN RESIDENTS RESALE RESTRICTIONS The distribution of the common stock in Canada is being made only on a private placement basis exempt from the requirement that we and the selling shareholder prepare and file a prospectus with the securities regulatory authorities in each province where trades of common stock are made. Any resale of the common stock in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the common stock. REPRESENTATIONS OF PURCHASERS By purchasing common stock in Canada and accepting purchase confirmation a purchaser is representing to us, the selling shareholder and the dealer from whom the purchase is received that: - the purchaser is entitled under applicable provincial securities laws to purchase the common stock without the benefit of a prospectus qualified under those securities laws; - where required by law, the purchaser is purchasing as principal and not as agent; and - the purchaser has reviewed the test above under Resale Restrictions. 96 101 RIGHTS OF ACTION (ONTARIO PURCHASERS) The securities being offered are those of a foreign issuer and Ontario purchasers will not receive the contractual right of action prescribed by Ontario securities law. As a result, Ontario purchasers must rely on other remedies that may be available, including common law rights of action for damages or rescission or rights of action under the civil liability provisions of the U.S. federal securities laws. ENFORCEMENT OF LEGAL RIGHTS All of the issuer's directors and officers as well as the experts named herein and the selling shareholder may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon the issuer or such persons. All or a substantial portion of the assets of the issuer and such persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against the issuer or such persons in Canada or to enforce a judgment obtained in Canadian courts against the issuer or such persons outside of Canada. NOTICE TO BRITISH COLUMBIA RESIDENTS A purchaser of common stock to whom the Securities Act (British Columbia) applies is advised that the purchaser is required to file with the British Columbia Securities Commission a report within ten days after the sale of any common stock acquired by the purchaser pursuant to this offering. The report must be in the form attached to British Columbia Securities Commission Blanket Order BOR #95/17, a copy of which may be obtained from us. Only one report must be filed for common stock acquired on the same date and under the same prospectus exemption. TAXATION AND ELIGIBILITY FOR INVESTMENT Canadian purchasers of common stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the common stock in their particular circumstances and about the eligibility of the common stock for investment by the purchaser under relevant Canadian legislation. MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF OUR COMMON STOCK This is a general discussion of U.S. federal tax consequences of the acquisition, ownership and disposition of our common stock by a non-U.S. holder, or a beneficial holder that, for U.S. federal income tax purposes, is a nonresident alien individual, a foreign corporation, a foreign partnership or a foreign estate or trust. We have based this summary upon the U.S. federal tax laws in effect as of the date of this prospectus. These laws may change, possibly retroactively. As noted below, some of these laws are expected to change for periods beginning after December 31, 2000. We do not discuss all aspects of U.S. federal taxation that may be important to you in light of your particular circumstances, such as special tax rules that apply if you are a financial institution, insurance company, broker-dealer, tax-exempt organization or investor holding our common stock as part of a "straddle" or other integrated investment. We urge you to consult your tax advisor about the U.S. federal tax consequences of acquiring, holding and disposing of our common stock, as well as any tax consequences that may arise under the laws of any foreign, state, local or other taxing jurisdiction. DIVIDENDS Dividends paid to a non-U.S. holder will generally be subject to withholding of U.S. federal income tax at the rate of 30%, or such lower rate as may be provided by an applicable income tax treaty between the U.S. and the country of which the non-U.S. holder is a tax resident. If, however, the dividend is effectively connected with the conduct of a trade or business in the U.S. by the non-U.S. holder, the dividend will be exempt from withholding (subject to satisfaction of applicable certification procedures, including the filing of Internal Revenue Service Form W-8ECI) and will instead be subject to the 97 102 U.S. federal income tax imposed on net income on the same basis that applies to U.S. persons generally (assuming if required by an applicable tax treaty, the dividends are attributable to a permanent establishment maintained by the non-U.S. holder within the U.S.), and for corporate holders and under some circumstances, the branch profits tax. For purposes of determining whether tax is to be withheld at a reduced rate as specified by a treaty, recently finalized Treasury regulations (which in general are expected to apply to dividends that we pay after December 31, 2000) require a non-U.S. holder generally to provide an Internal Revenue Service Form W-8BEN certifying that non-U.S. holder's entitlement to treaty benefits. These regulations also provide special rules to determine whether, for treaty applicability purposes, dividends that we pay to a non-U.S. holder that is an entity should be treated as paid to holders of interests in that entity. GAIN ON DISPOSITION A non-U.S. holder will generally not be subject to U.S. federal income tax, including by way of withholding, on gain recognized on a sale or other disposition of our common stock unless: - the gain is effectively connected with the conduct of a trade or business in the U.S. by the non-U.S. holder or - in the case of a non-U.S. holder who is a nonresident alien individual and who holds our common stock as a capital asset, that holder is present in the U.S. for 183 or more days in the taxable year of the disposition and certain other requirements are met. Gain that is effectively connected with the conduct of a trade or business in the U.S. by the non-U.S. holder will be subject to the U.S. federal income tax imposed on net income on the same basis that applies to U.S. persons generally, and, for corporate holders and under some circumstances, the branch profits tax, but will not be subject to withholding. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules. U.S. FEDERAL ESTATE TAXES Our common stock that is owned or treated as owned by an individual who is not a citizen or resident of the U.S., as specially defined for U.S. federal estate tax purposes, on the date of that person's death will be included in his or her estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise. INFORMATION REPORTING AND BACKUP WITHHOLDING Generally, we must report annually to the U.S. Internal Revenue Service and to each non-U.S. holder the amount of dividends that we paid to a holder and the amount of tax that we withheld on those dividends. This information may also be made available to the tax authorities of a country in which the non-U.S. holder resides. Pursuant to recently finalized Treasury regulations which in general are expected to apply to payments we make after December 31, 2000, a non-U.S. holder will be entitled to an exemption from information reporting requirements and backup withholding tax on dividends that we pay on our common stock if the non-U.S. holder provides a Form W-8BEN (or satisfies certain documentary evidence requirements for establishing that it is a non-U.S. holder) or otherwise establishes an exemption. Payments by a U.S. office of a broker of the proceeds of a sale of our common stock are subject to both backup withholding at a rate of 31% and information reporting, unless the holder certifies its non-U.S. holder status under penalties of perjury or otherwise establishes an exemption. Information reporting requirements, but not backup withholding, will also apply to payments of the proceeds from sales of our common stock by foreign offices of U.S. brokers, or foreign brokers with certain types of relationships to the U.S., unless the broker has documentary evidence in its records that the 98 103 holder is a non-U.S. holder and certain other conditions are met, or the holder otherwise establishes an exemption. Backup withholding is not an additional tax. Any amounts that we withhold under the backup withholding rules will be refunded or credited against the non-U.S. holder's U.S. federal income tax liability, if the required information is furnished to the U.S. Internal Revenue Service. LEGAL MATTERS Matters relating to the validity of the shares of common stock being offered by this prospectus will be passed upon for us by William H. Stephens III, our Executive Vice President, General Counsel and Secretary. As of November 15, 2000, Mr. Stephens beneficially owned approximately 41,949 shares of CMS Energy common stock. Other legal matters in connection with the offering will be passed upon for us by Sidley & Austin, Chicago, Illinois and William H. Stephens III and for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. As of November 15, 2000, an attorney currently employed by Skadden, Arps, Slate, Meagher & Flom LLP, and formerly employed by CMS Energy, owned stock and other securities of CMS Energy and Consumers. His holdings consisted of approximately 51,734 shares of CMS Energy common stock, 10 shares of Consumers $4.50 Series preferred stock, $100 par value, and $50,000 aggregate principal amount of certain debt securities of CMS Energy. EXPERTS The consolidated financial statements as of December 31, 1998 and 1999 and for each of the three years in the period ended December 31, 1999 included in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. INDEPENDENT PETROLEUM ENGINEERS The estimated reserve evaluations and related calculations of Ryder Scott Company, L.P. and Lee Keeling and Associates, Inc. (with respect to our Colombian reserves up to and including January 1, 2000), our independent petroleum engineers, have been included in this prospectus in reliance upon the authority of those firms as experts in petroleum engineering. 99 104 WHERE YOU CAN FIND MORE INFORMATION We have filed with the SEC a registration statement on Form S-1 under the Securities Act of 1933, as amended, with respect to the common stock offered by this prospectus. This prospectus, which constituted part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits thereto. For further information with respect to us and our common stock, reference is hereby made to the registration statement and the exhibits thereto. Statements contained in this prospectus as to the contents of any contract, agreement or other document referred to are not necessarily complete, and in each instance, reference is made to the copy of the contract, agreement or other document filed as an exhibit to the registration statement for a more complete description of the matters involved, each such statement being qualified in all respects by such reference. The registration statement and the exhibits thereto may be inspected and copied at the public reference facilities maintained by the SEC located at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549, as well as at the regional offices of the SEC located at Seven World Trade Center, Suite 1300, New York, New York 10048, and 500 West Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of this material can also be obtained at prescribed rates by writing to the SEC's Public Reference Section at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for additional information about its public reference facilities and copy charges. This information may also be accessed electronically by means of the SEC's website on the Internet at http://www.sec.gov. As a result of this offering, we will be subject to the information requirements of the Exchange Act of 1934, as amended, and, in accordance with that Act, will file reports, proxy statements and other information with the SEC on a periodic basis. The reports, proxy statements and other information that we file with the SEC can be inspected and copied at the offices of the SEC, at the website listed above and at the offices of The New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005. We intend to furnish our shareholders with annual reports containing audited financial statements examined by our independent auditors for each fiscal year. CMS Energy is subject to the information requirements of the Exchange Act. You may obtain copies of the documents that CMS Energy files with the SEC at the offices of the SEC or by means of the SEC's website listed above. The documents filed with the SEC by CMS Energy are not deemed to be a part of this prospectus or the registration statement of which it forms a part. 100 105 GLOSSARY OF OIL AND NATURAL GAS TERMS We have used the following terms relating to the oil and gas industry throughout this prospectus: Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcf. One billion cubic feet. Boe or net equivalent barrels. Barrels of oil equivalent with natural gas volumes converted to barrels of oil equivalents using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil. Btu. British thermal unit; the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. There are approximately 1,050 Btus in each standard cubic foot of natural gas. Completion. The installation of permanent equipment for the production of oil or gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. Condensate. A hydrocarbon mixture that becomes liquid and separates from natural gas when the gas is produced; similar to crude oil. Development well. A well drilled within the proved area of an oil and gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves or to economically accelerate production of reserves classified as proved developed. Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploratory well. A well drilled to find and produce oil or gas in an unproved area or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Farm-in or Farm-out. An agreement whereunder the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out." Field. An area consisting of single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Gross. "Gross" oil and gas wells or "gross" acres are the total number of wells or acres in which we have an ownership interest, without regard to the size of that ownership interest. Horizontal drilling. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and can result in both increased production rates and greater ultimate recoveries of hydrocarbons. LPG. Liquefied petroleum gas. MBbls. One thousand barrels of oil or other liquid hydrocarbons. MBoe. One thousand Boe. Mcf. One thousand cubic feet. MMBbls. One million barrels of oil or other liquid hydrocarbons. MMBoe. One million Boe. MMBtu. One million Btus. MMcf. One million cubic feet. 101 106 Natural gas liquids (NGLs) or plant products. Butane, propane, ethane, natural gasoline and other liquid hydrocarbons that are extracted from natural gas. Net. "Net" oil and gas wells or "net" acres are determined by multiplying gross wells or acres by our working interest in those wells or acres. Net present value. When used with respect to oil and gas reserves, the estimated future gross revenue to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%. Net revenue interest. The percentage of production to which the owner of a working interest is entitled. For example, the owner of a 100% working interest in a well burdened only by a landowner's royalty of 12.5% would have an 87.5% net revenue interest in that well. Oil. Crude oil and condensate. Operator. The individual or company responsible for conducting oil and gas exploration, development and production activities on an oil and gas lease or concession on its own behalf and, if applicable, for other working interest owners, generally pursuant to the terms of a joint operating agreement or comparable agreement. Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of certain costs of production. Producing well. A well that is producing oil or gas or that is capable of production. Proved (or proven) developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods under existing economic and operating conditions. Proved (or proven) reserves. The estimated quantities of oil, natural gas, natural gas liquids and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved (or proven) undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Recompletion. Recompletion refers to the completion of an existing well for production from a formation that exists behind the casing of the well. Reserve life. The proved reserves divided by the average annualized production volumes. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production. Seismic. The use of shock waves generated by controlled explosions of dynamite or other means to ascertain the nature and contour of underground geological structures. Spud. To start to drill a well. Tcf. One trillion cubic feet. 102 107 Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves. Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. Workover. Operations on a producing well to restore or increase production. 2-D seismic. Seismic that is run, acquired and processed to yield a two-dimensional picture of the subsurface. 3-D seismic. Seismic that is run, acquired and processed to yield a three-dimensional picture of the subsurface. Three dimensional seismic is relatively expensive because it takes a considerable amount of computer time to process the data. 103 108 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

F-1 109 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors, CMS Oil and Gas Company We have audited the accompanying consolidated balance sheets of CMS Oil and Gas Company (a Michigan corporation and wholly-owned subsidiary of CMS Enterprises Company) and subsidiaries as of December 31, 1998 and 1999, and the related consolidated statements of income, stockholder's equity and cash flows for each of the three years in the period ended December 31, 1999. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CMS Oil and Gas Company and subsidiaries as of December 31, 1998 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas February 28, 2000 F-2 110 CMS OIL AND GAS COMPANY CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these statements. F-3 111 CMS OIL AND GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME

The accompanying notes are an integral part of these financial statements. F-4 112 CMS OIL AND GAS COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY

The accompanying notes are an integral part of these statements. F-5 113 CMS OIL AND GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these statements. F-6 114 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS) 1. SIGNIFICANT ACCOUNTING POLICIES CMS Oil and Gas Company (the "Company") is a wholly-owned subsidiary of CMS Enterprises Company (the "Parent") and a second-tier subsidiary of CMS Energy Corporation ("CMS Energy"). The Company and its subsidiaries are engaged in the exploration, development, acquisition and production of oil and natural gas, including the extraction and sale of natural gas liquids. The Company's oil-producing assets are concentrated in South America (Colombia and Venezuela) and Africa (the Congo, Equatorial Guinea and Tunisia), and the Company's gas-producing assets are concentrated in the U.S. (Texas, Wyoming, Montana and Louisiana), Equatorial Guinea and Tunisia. In June 1997, the Company relocated its headquarters to Houston, Texas from Jackson, Michigan. Certain reclassifications have been reflected in the prior years' amounts to conform to the 1999 presentation. A summary of significant accounting policies is set forth below: Basis of Presentation The Consolidated Financial Statements include the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated. The unaudited consolidated financial statements as of September 30, 2000 and for the nine-month periods ended September 30, 1999 and 2000, and all related footnote information for these periods have been prepared on the same basis as the audited financial statements and, in the opinion of management, include all adjustments, consisting of normal recurring adjustments necessary for a fair presentation of financial position, results of operations and cash flows in accordance with generally accepted accounting principles. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Revenue Recognition Oil and gas revenues are recognized as production takes place and the sale is completed and the risk of loss transfers to a third party purchaser. The Company follows the cash method of accounting for production imbalances for all gas properties. Under this method, the Company recognizes revenues or production as it is taken and delivered to its purchasers. F-7 115 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company and its parents (direct and indirect) have a price risk management policy to reduce the price risk associated with the fluctuations in oil and natural gas prices. Commodity derivatives utilized as hedges include futures, swaps and option contracts, which are used to hedge oil and natural gas prices. In order to qualify as a hedge price, movements in the underlying commodity derivative must be highly correlated with the hedged commodity. Realized gains and losses from the Company's price risk management activities are recognized in oil and gas production revenues when the associated production occurs. In these Consolidated Financial Statements, net hedging activity is included in revenues from oil and condensate or natural gas sales, as applicable. Net hedging activities have increased (decreased) oil and condensate and natural gas sales by the following:

Inventory Crude oil and condensate inventory from the Company's Congo fields is produced into a floating production, storage and off-loading system and sold periodically as an economic vessel quantity is accumulated. The crude and condensate inventory is carried at its estimated net realizable value. Materials and supplies consist primarily of goods used in the Company's operations and are stated at the lower of average cost or market. Temporary Cash Investments All highly liquid investments with an original maturity of three months or less are considered temporary cash investments. Oil and Gas Properties 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 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. Interest costs relating to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until the production commences if the projects are evaluated as successful. 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. F-8 116 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) ] Income Taxes The Company follows Statement of Financial Accounting Standard ("SFAS") No. 109, "Accounting for Income Taxes." Under the asset and liability method of SFAS No. 109, deferred tax assets and liabilities are recognized for the future tax consequence, attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. The Company has entered into a tax sharing agreement with CMS Energy. The agreement generally provides that, for any taxable period in which the Company is included in the CMS Energy consolidated tax return, the amount of income taxes to be paid by the Company will be determined as if the Company had filed a separate income tax return. Comprehensive Income In accordance with SFAS No. 130 "Reporting Comprehensive Income," the Company has reported comprehensive income in the Consolidated Statement of Stockholder's Equity. Comprehensive Income consists of the changes in value of the Company's Supplemental Executive Retirement Plan. Earnings per Share Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. For the years ended December 31, 1997, 1998 and 1999, the Company did not have any potentially dilutive securities. Foreign Currency The U.S. dollar is the functional currency for all significant areas of operations of the Company. Therefore, there are no exchange gains or losses resulting from the translation of foreign financial statements in the Company's consolidated financial statements. Certain foreign subsidiaries conduct operations in the Country's local currency. Exchange gains or losses resulting from these transactions are recognized currently in the Company's income statement. Accounting for Investments The Company uses the proportionate consolidation method of accounting for all of its working interest, while investments in less than majority owned companies are accounted for on the equity method of accounting. Pension Plan and Supplemental Executive Retirement Plan The Company participates in an affiliate's trusteed noncontributory defined benefit plan (the "Plan") covering full-time regular employees within specified age limits and periods of service. Pension expenses amounted to approximately $0.2 million for each of the years ended December 31, 1997, 1998 and 1999. Company employees are not segregated in the Plan and it is not possible to determine the vested benefit obligation and related Plan assets with respect to Company employees. The affiliate has indicated that assets available for Plan benefits are in excess of the accumulated benefit obligation. The Company participates in CMS Energy's Supplemental Executive Retirement Plan ("SERP") for certain management employees. SERP benefits, which are based on an employee's years of service and earnings as defined in the SERP, are paid from a trust established and funded in 1988. Because the SERP is a nonqualified plan under the Internal Revenue Code, earnings of the trust are taxable and trust assets are included in the consolidated assets of the Company. F-9 117 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Health Care and Life Insurance Benefits The Company's health care and life insurance benefit plans for its employees and retirees are self-insured by CMS Energy. The post-retirement plans are noncontributory and currently underfunded. The Company accounts for the cost of these plans on an accrual method as required by SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other than Pensions." New Accounting Pronouncement In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Investments and Hedging Activities." SFAS 133 establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the income statement or other comprehensive income, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. In June 1999, the FASB issued SFAS No. 137 which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. A company may implement SFAS 133 as of the beginning of any fiscal quarter after issuance, however, the statement cannot be applied retroactively. The Company does not plan to early adopt SFAS 133. The Company has not yet assessed the effectiveness of the Company's September 30, 2000 derivative contracts and therefore cannot quantify the impact of adoption of SFAS 133. If the Company assumed all derivative contracts at September 30, 2000 were ineffective, the Company would have recorded a current liability and pretax net income would be reduced by approximately $25.2 million, representing the fair value of all derivatives at that date. 2. PURCHASES OF OIL AND GAS PROPERTIES During 1997, the Company purchased an additional 14.58% working interest in the Colon Block in Venezuela and also purchased an additional 33.33% working interest in the Espinal Block in Colombia for an aggregate total of $2.9 million. During 1998, the Company purchased an additional 6.25% working interest in the Marine I Permit in the Congo for approximately $7.6 million. The Company also acquired an additional 2.4% working interest in the Bioko Permit offshore Equatorial Guinea for approximately $5.9 million. In late 1998, the Company also acquired undeveloped, non-producing leasehold acreage in the Powder River Basin for approximately $27.9 million. In October 1999, the Company purchased an additional 11.5% working interest in the Bioko Permit offshore Equatorial Guinea for approximately $53.3 million. F-10 118 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. LONG-TERM DEBT Long-term debt consisted of the following:

As of December 31, 1999, principal maturities of long-term debt over the next five years were as follows:

In May 1999, the Company negotiated the maturity and other terms of the $225 million Credit Facility with a group of banks. Borrowings under the Credit Facility are revolving credit loans for three years. The Credit Facility provides various options to the Company relative to interest rates and also requires a facility fee. The aggregate borrowing base under the Credit Facility is limited to the estimated loan value of the Company's oil and natural gas reserves subject to certain exclusions based upon forecast rates of production and current commodity pricing as periodically predetermined by the banks which are parties to the Credit Facility. The banks have broad discretion in determining which of the Company's reserves to include in the borrowing base. The total borrowing base at December 31, 1999 under the Credit Facility was $210 million. Of the total amount available, $175 million in borrowings were outstanding as of December 31, 1999. Under the terms of the Credit Facility, the Company must maintain: (1) a ratio of total indebtedness to total capitalization of no more than 0.60 to 1, (2) a minimum tangible net worth, as defined, of $275 million plus 50% of the positive net income commencing with quarter income ended June 30, 1999 plus 50% of the net proceeds of any equity sale, as defined, (3) a ratio of EBITDA to interest greater than 2.75 to 1, and (4) consolidated debt to adjusted cash flow, of 4.25 to 1 for any fiscal quarter ending at any F-11 119 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) time on or after December 31, 1999 to and including September 30, 2000, or 3.75 to 1 for any fiscal quarter thereafter. Restrictive covenants under the Credit Facility include certain limitations on indebtedness and contingent obligations, as well as certain restrictions on liens, investments, affiliate transactions and sales of assets. In addition, the banks have the right to require the Company to repay all advances under the Credit Facility within 90 days after notification to the banks that (1) CMS Energy no longer beneficially owns a majority of the outstanding voting stock of the Company or (2) all or substantially all of the assets of the Company are sold. As of December 31, 1999, the Company's total indebtedness to total capitalization was 0.40 to 1; its tangible net worth was $350.1 million; its EBITDA to interest coverage ratio was 4.8 to 1; and its consolidated debt to adjusted cash flow ratio was 2.4 to 1. As of December 31, 1999, $0.8 million of project financing debt was outstanding under agreements with Overseas Private Investment Corporation ("OPIC"). These OPIC guaranteed loans funded acquisition and development of the Yombo Field in the Congo. In August 1995, the Company issued a note in the principal amount of approximately $61.3 million to the Parent which in turn assigned it to CMS Energy in connection with the transfer by CMS Energy of the common stock of Terra Energy, Ltd. to the Parent and then by the Parent to the Company, and in May 1995, the Company issued another note in the principal amount of approximately $6.5 million to CMS Energy in connection with borrowings made to repay $6.5 million of indebtedness of Walter International, Inc. immediately upon the closing of the Walter acquisition (the Terra note and the Walter note together are referred to as the "CMS Notes"). During the second quarter of 1999 the Terra Note was amended to extend the maturity to April 15, 2009 and suspend the interest payments until April 14, 2004. Interest will accrue and be added to the outstanding debt balance. The outstanding balance of the CMS Notes at December 31, 1999 was $58.5 million. The CMS Notes bear interest at the rate of three-month London Interbank Offered Rate ("LIBOR") plus 2% per annum and have a maturity date of November 1, 2003. Amounts outstanding under the CMS Notes are expressly subordinate to the Credit Facility. Certain limitations are placed on the Company's obligations to make payments on the CMS Notes in the event of default under the terms of the Credit Facility. 4. INCOME TAXES The Company and its consolidated subsidiaries join with CMS Energy in filing a consolidated U.S. tax return. Taxable income or loss is determined for the Company and its subsidiaries as if they were filing separate income tax returns. Tax benefits for losses and nonconventional fuel tax credits ("Section 29 tax credits") are recognized by the Company to the extent utilized in the consolidated return. Because the Company has been included in the consolidated federal income tax return filed by CMS Energy, these Section 29 tax credits have either been used currently to reduce the tax liability of the CMS Energy consolidated group or have created an alternative minimum tax credit carryforward for use in future years. CMS Energy reimburses the Company for the Section 29 tax credits and other tax benefits used in its consolidated tax return. The income tax benefit receivable from CMS Energy was $21.5 million and $27.6 million as of December 31, 1998 and 1999, respectively. To the extent required by local law, the Company and certain of its subsidiaries file income and other tax returns in those foreign countries in which the Company does business. The Company does not record deferred U.S. taxes on the undistributed earnings of its foreign subsidiaries as such earnings are intended to be permanently reinvested. If distributed, those earnings would be subject to both U.S. income taxes (subject to adjustment for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. As of September 30, 2000, the Company had approximately $91.0 million of undistributed earnings for which no U.S. taxes have been provided. Should F-12 120 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) these funds be repatriated, then up to an additional $32.0 million in U.S. taxes would be charged to income. Significant components of income taxes were as follows:

Total income taxes were as follows:

At December 31, 1999, the Company's wholly-owned subsidiaries have approximately $129.2 million of net operating loss carryforwards generated in foreign taxing jurisdictions. These foreign net operating loss carryforwards are available to offset taxable income only in the jurisdiction in which the corresponding losses occurred. The losses carry forward until utilized, until they lapse under the respective taxation regime or the wholly-owned subsidiaries which generated the losses withdraw from business activities within the respective taxing jurisdiction. These foreign tax credits will begin expiring in 2001 and end in 2011. F-13 121 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The principal components of the Company's deferred tax assets (liabilities) recognized in the Consolidated Balance Sheets are as follows:

The actual income tax provision (benefit) differ from the amount computed by applying the statutory U.S. federal tax rate to income before income taxes as follows:

F-14 122 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. RELATED PARTY TRANSACTIONS The Company markets natural gas to affiliates at rates approximating the average price of natural gas paid to other area producers. Total natural gas marketed to an affiliate, Consumers Energy Company, was approximately $25.4 million in 1997, $24.2 million in 1998 and $17.8 million in 1999. Total natural gas marketed to another affiliate, CMS Marketing, Services and Trading Company, was approximately $30.8 million, $29.6 million, and $26.5 million in 1997, 1998 and 1998, respectively. Natural gas marketed to the Midland Cogeneration Venture amounted to approximately $10.8 million, $7.6 million and $10.1 million in 1997, 1998 and 1999, respectively. Other intercompany transactions, principally services, are billed at cost. For the year ended December 31, 1999, the Company incurred a $0.4 million service fee for crude oil marketing services by a partially owned affiliate of CMS Marketing, Services and Trading Company. For each of the years ended December 31, 1997 and 1998, the Company incurred a $0.2 million service fee for marketing services by an affiliate, CMS Marketing, Services and Trading Company, and for the year ended December 31, 1999, the Company incurred a $0.1 million service fee for marketing services for natural gas. 6. HEALTH CARE AND LIFE INSURANCE BENEFITS For measurement purposes, a 7.0% annual rate of increase was assumed in the per capita cost of covered health care benefits for 1999. The rate was assumed to gradually decrease to 6.0% per annum by the year 2005 and thereafter. The health care cost trend rate assumption has an impact on the accumulated postretirement benefit obligation and on future amounts accrued. For the years ended December 31, 1998 and 1999, the weighted average discount rates were 7.75% per annum, and the expected long term rate of return on plan assets was 7.0% for both years. The health care cost trend rate assumption significantly affects the amounts reported. A one-percentage point change in the assumed health care cost trend assumption would have the following effects:

F-15 123 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The funded status of the postretirement benefit plans is reconciled with the liability recorded as follows:

7. CAPITAL STOCK The Company's capital stock consists of one class of common stock, with no par value, and 5 million shares of preferred stock, with no par value. There are 55 million shares of common stock authorized and 20 million shares issued and outstanding as of December 31, 1998 and 1999, respectively. The holders of the common stock are entitled to one vote per share on all matters submitted to a vote of shareholders. All outstanding shares are held by CMS Enterprises. The Company has the authority to issue up to 5 million shares of preferred stock in one or more series and to fix and determine the relative rights and preferences of the preferred stock. There are no shares of preferred stock issued and outstanding. 8. SIGNIFICANT CUSTOMERS Revenues from sales to the Company's largest customers (greater than 10%) as a percent of total Company revenues were:

9. COMMITMENTS AND CONTINGENCIES The Company estimates its exploration and development expenditures for 2000 will be $152.6 million and certain commitments have been made in connection therewith. F-16 124 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Dual Consolidated Losses Under agreements relating to the Company's 1995 acquisition of Walter International, Inc. and its Congo operations, CMS Energy and the Company could become jointly and severally liable for the recapture of "dual consolidated losses" under Section 1503(d) of the Internal Revenue Code if a "triggering event" were to occur. Potential triggering events include certain asset or stock dispositions to unrelated parties, certain tax deconsolidations, certain usage of the losses on a foreign tax return and certain failures to comply with IRS regulations. CMS Energy and the Company have no plans to effect any transaction that would be a triggering event. The amount of the potential tax liability could be up to $67 million plus interest. In connection with the same acquisition, a subsidiary of the Company could also be jointly and severally liable with an unrelated party for up to $48 million of tax plus interest. In that event, the Company has certain indemnity rights against that unrelated party. Additionally, the Company and its domestic subsidiaries have incurred losses in certain foreign countries that could be recaptured if a triggering event were to occur. The additional tax liability could be up to $10 million plus interest. Hedging Arrangements The Company enters into oil and gas price hedging arrangements with an affiliate to mitigate its exposure to price fluctuations on the sale of crude oil and natural gas. The Company received $1.8 million in 1997 and made net payments of $20.3 million in 1999 for settlements of its crude oil contracts. There were no crude oil hedging contracts in 1998. The Company paid $7.4 million in 1997, received $2.9 million in 1998 and paid $0.1 million in 1999 for settlement of its natural gas contracts. As of December 31, 1999 the Company had entered into 2000 hedging arrangements with an affiliate on 18.8 Bcf of natural gas at an average price of $2.61 per Mcf and 5.7 million barrels of oil at an average price of $15.62 per barrel. The contracts are accounted for as hedges; accordingly, changes in market value and gains or losses from settlements are deferred and recognized at such time as the hedged transaction is completed. If there were a loss of correlation between the changes in (1) the market value of the derivative contracts and (2) the market price ultimately received for the hedged item, and the impact was material, the open commodity price contracts would be marked to market and gains and losses would be currently recognized in the statement of income currently. The Company has also hedged certain of its natural gas supply obligations to the Midland Cogeneration Venture in the years 2001 through 2006 by entering into an agreement with Louis Dreyfus Natural Gas on May 1, 1989 to purchase the economic equivalent of 10,000 MMBtu per day at a fixed price, escalating at 8% per year thereafter, starting at $2.82 per MMBtu in 2001. The settlement periods are each a one-year period ending December 31, 2001 through 2006 on 3.65 million MMBtu. If the floating price, essentially the then-current Gulf Coast spot price for a period, is higher than the fixed price, the seller pays the Company the difference and vice versa. The contract with Louis Dreyfus Natural Gas provides a calculation of exposure for the purpose of requiring an exposed party to post a standby letter of credit. Under this calculation, if a party's exposure at any time exceeds $5 million, that party is required to obtain a letter of credit in favor of the other party for the excess over $5 million up to a maximum standby letter of credit of $10 million. At December 31, 1999, a letter of credit was not required by either party to the agreement. The letter of credit obligation does not necessarily bear any relation to the market value of the contract. As of December 31, 1999, the fair market value of the contract reflected a payment due to Louis Dreyfus Natural Gas of $19.3 million. The Company believes the market is thin for contracts with settlement periods comparable to the Company's contract with Louis Dreyfus Natural Gas. In the second quarter of 2000, the Company assigned this agreement to an affiliate. Although the affiliate has assumed the Company's obligations under the agreement, the Company remains liable for the obligations if the affiliate should fail to fulfill its obligations. F-17 125 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company had entered into two-interest rate swap agreements, which effectively fixed the interest rate on $30 million of floating rate debt. The swap agreements included (1) a $15 million interest rate swap which matured February 19, 1998 at 5.952 % and (2) a $15 million interest rate swap which matured August 19, 1998 at 6.069 %. Both swaps required quarterly settlement based on a three-month LIBOR rate. Other The Company is party to certain lawsuits and administrative proceedings arising in the ordinary course of business before various courts and governmental agencies involving, for example, claims for personal injury and property damages, contractual matters, environmental issues, tax issues and other matters. Management cannot predict the ultimate resolution of these matters but it believes the resulting liabilities, if any, will not have a material adverse effect upon the Company's financial position or results of operations or cash flows. In 1999 the Company's former subsidiary, Terra Energy Ltd., was sued by Star Energy and White Pines Enterprises on grounds, among others, that Terra violated oil and gas lease and other agreements by failing to drill wells it had committed to drill. Among the defenses asserted by Terra were that the wells were not required to be drilled and the claimant's sole remedy was termination of the oil and gas lease. During trial the judge declared the lease terminated in favor of White Pines. The jury then awarded Star and White Pines $7.6 million in damages. Terra has filed an appeal. The Company believes Terra has meritorious grounds for reversal of the judgment. The Company has an indemnification obligation in favor of the purchaser of its Michigan properties with respect to this litigation. 10. FINANCIAL INSTRUMENTS The carrying amounts of cash, temporary cash investments and current liabilities approximate their fair values due to their short-term nature. The carrying amounts of long-term debt were $230.4 million and $236.4 million as of December 31, 1998 and 1999, respectively. The fair value of such debt is substantially equal to the carrying value due to the stated interest rates approximating market rates at December 31, 1998 and 1999. The fair values of the Company's off-balance sheet financial instruments are based on the amounts estimated to terminate or settle the instruments. See note 9 of the consolidated financial statements of the Company. 11. LEASES The Company and its subsidiaries lease various assets, including vehicles, office equipment and office space under leases expiring on various dates through 2008. Rental expense under these leases was $1.2 million, $1.2 million and $1.1 million for the years ended December 31, 1997, 1998 and 1999, respectively. F-18 126 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Minimum rental commitments under the Company's non-cancelable leases at December 31, 1999, were as follows (capital leases are presented net of imputed interest):

12. PROPERTY, PLANT AND EQUIPMENT Investments in property, plant and equipment were as follows:

Depreciation, depletion and amortization for oil and gas properties for the years ended December 31, 1997, 1998 and 1999 were $47.1 million, $36.2 million and $41.7 million, respectively. 13. OTHER OPERATING REVENUES Other operating revenues were as follows:

F-19 127 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 14. GEOGRAPHIC AREA INFORMATION Pertinent information with respect to the Company's business is presented in the following table:

--------------- * Includes exploration and development expenditures and identifiable assets attributable to the Company's equity investment in Comeco; see Supplemental Information following the Notes to the Consolidated Financial Statements. 15. SUBSEQUENT EVENTS (UNAUDITED) The Company's indirect parent CMS Energy Corporation announced in January 2000 that it had signed a letter of intent to sell all of the Company's Michigan oil and gas producing properties to Quicksilver Resources, Inc. for approximately $162.9 million. The transaction closed on March 31, 2000 with an after-tax gain of $5.2 million. On June 30, 2000, the Company sold its 14% non-operated interest in Ecuador for $95.8 million and recognized a $29.6 million after-tax gain. F-20 128 CMS OIL AND GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In September 2000, CMS Energy announced its intention to sell up to 50% of its ownership in the Company through an initial public offering ("IPO"). In connection with the proposed IPO, the Company plans to acquire an indirect 45% interest in a methanol production plant from an affiliate for a non-interest bearing note of $137.0 million, refinance its existing debt by issuing $200.0 million of senior subordinated notes, and distribute a $39.0 million non-interest bearing note payable to the Parent. In addition to the proposed transactions, the Company intends to adopt a stock option plan for executive officers and other key employees, enter into various service agreements with CMS Energy and other affiliates and enter into oil and gas marketing and hedging agreements with affiliates. The Company has entered into change of control severance agreements with its executive officers. The Company currently is a member of the CMS Energy affiliate group of corporations that files its U.S. tax returns on a consolidated basis. (See Note 4). Upon completion of the IPO, the Company will cease to be a member of the affiliated group consolidated tax return and the Company will file a separate income tax return. F-21 129 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following information was prepared in accordance with the Supplemental Disclosure Requirements of SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." Refer to the Consolidated Statements of Income for the Company's results of operations from exploration and production activities provided elsewhere in the consolidated financial statements. The following estimates of proved reserves and future net cash flows before income taxes as of December 31, 1997, 1998 and 1999 have been prepared by Ryder Scott Company L.P. and/or Lee Keeling and Associates, Inc. These estimates do not purport to reflect realizable values or fair market values of the Company's reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The government license in Venezuela is an oil service contract whereby the Company is paid a fee per barrel for oil discovered, lifted and delivered to Maraven S.A., a subsidiary of Petroleos de Venezuela S.A. Additionally, the Company receives a fee for reimbursement of certain capital expenditures. The volumes presented represent actual production with respect to which the Company is paid a per barrel fee. Data related to the Company's equity investment in Yemen through Comeco is shown separately. 1. ESTIMATED PROVED RESERVES OF OIL AND NATURAL GAS

F-22 130 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

2. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED PROVED RESERVES

F-23 131 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

--------------- (1) Oil, natural gas and condensate revenues are based on year-end prices with adjustments for changes reflected in existing contracts. There is no consideration for future discoveries or risks associated with future production of estimated proved reserves. (2) Based on economic conditions at year-end. Does not include general, administrative or financing costs. Does not consider future changes in development or production costs. (3) Based on current statutory rates applied to future cash inflows reduced by future production and development costs, tax deductions and credits. Income tax expense has been reduced by $60.6 million, $43.4 million and $32.8 million due to the nonconventional fuels tax credit for Antrim gas produced at December 31, 1997, 1998 and 1999, respectively. F-24 132 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED) 3. RECONCILIATION OF THE CHANGE IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

4. NET INVESTMENT(1)

--------------- (1) Excluded are approximately $17.4 million ($12.5 million net of accumulated depreciation) in 1998 and $20.0 million ($13.8 million net of accumulated depreciation) in 1999 for non-oil and gas producing properties. As of December 31, 1999, the Company's non-U.S. investments in Colombia, Congo, Ecuador, Equatorial Guinea, Tunisia and Venezuela are subject to depletion. F-25 133 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED) 5. EXPLORATION, DEVELOPMENT AND ACQUISITION EXPENDITURES

--------------- (1) Certain reclassifications have been reflected in the 1997 and 1998 amounts to conform with the 1999 presentation. F-26 134 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED) 6. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES The following tables set forth the Company's results of operations from oil and gas producing activities for the years ended December 31, 1997, 1998 and 1999. Income taxes are computed by applying the appropriate statutory rate to the results of operations before income taxes. Applicable tax credits, permanent differences and allowances related to oil and gas producing activities have been taken into account in computing income taxes. The results of operations below do not include general and administrative expenses, general taxes and net interest expense.

F-27 135 CMS OIL AND GAS COMPANY SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

--------------- (1) The effects of hedging activities are included in oil and condensate revenues or natural gas revenues depending on the nature of the hedge instrument. See note 9 of the audited financial statements presented elsewhere in this report. (2) The computation of income taxes has been restated to conform to the 1999 presentation. F-28 136 APPENDIX A [RYDER SCOTT LETTERHEAD] November 10, 2000 CMS Oil and Gas Company 1021 Main Street, Suite 2800 Houston, TX 77002-6606 Gentlemen: At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of CMS Oil and Gas Company (CMS) as of September 30, 2000. The income data were estimated using Securities and Exchange Commission (SEC) future cost and price parameters. The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. CMS provided us with September 2000 prices; however, actual future prices may vary significantly from the September 2000 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. A summary of the results of this study is shown below. SEC PARAMETERS ESTIMATED NET RESERVES AND INCOME DATA CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF CMS OIL AND GAS COMPANY AS OF SEPTEMBER 30, 2000

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The proved developed non-producing reserves included herein are comprised of the shut-in and behind pipe categories. The various producing status categories are defined under the tab "Reserve Definitions and Pricing Assumptions" in this report. The future gross revenue is after the deduction of production taxes. The deductions are comprised of the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and transportation and marketing charges. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. No attempt A-1 137 CMS Oil and Gas Company November 10, 2000 Page 2 was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. Liquid hydrocarbon reserves account for approximately 77 percent and gas reserves account for 23 percent of total future gross revenue from proved reserves for those properties analyzed in this report. The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.

The results shown above are presented for your information and should not be construed as our estimate of fair market value. RESERVES INCLUDED IN THIS REPORT The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletin. Our definition of proved reserves is included under the tab "Reserve Definitions and Pricing Assumptions" in this report. Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled, and reserves assigned to the undeveloped portions of secondary or tertiary projects which we have been assured will definitely be developed. The various reserve status categories are defined under the tab "Reserve Definitions" in this report. ESTIMATES OF RESERVES In general, the reserves included herein were estimated by performance methods or the volumetric method; however, other methods were used in certain cases where characteristics of the data indicated such other methods were more appropriate in our opinion. The reserves estimated by the performance method utilized extrapolations of various historical data in those cases where such data were definitive in our opinion. Reserves were estimated by the volumetric method in those cases where there were inadequate historical performance data to establish a definitive trend or where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. A-2 138 CMS Oil and Gas Company November 10, 2000 Page 3 FUTURE PRODUCTION RATES Initial production rates are based on the current producing rates for those wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations which are not currently producing. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by CMS. In general, we estimate that future gas production rates will continue to be the same as the average rate for the latest available 12 months of actual production until such time that the well or wells are incapable of producing at this rate. The well or wells were then projected to decline at their decreasing delivery capacity rate. Our general policy on estimates of future gas production rates is adjusted when necessary to reflect actual gas market conditions in specific cases. The future production rates from wells now on production may be more or less than estimated because of changes in market demand or allowables set by regulatory bodies. Wells or locations which are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates. HYDROCARBON PRICES CMS furnished us with hydrocarbon prices in effect at September 30, 2000 and with its forecasts of future prices which take into account SEC and Financial Accounting Standards Board (FASB) rules, current market prices, contract prices, and fixed and determinable price escalations where applicable. In accordance with FASB Statement No. 69, September 30, 2000 market prices were determined using the daily oil price or daily gas sales price ("spot price") adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to September 30, 2000 were not considered in this report. For hydrocarbon products sold under contract, the contract price including fixed and determinable escalations, exclusive of inflation adjustments, was used until expiration of the contract. Upon contract expiration, the price was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. The effects of derivative instruments designated as price hedges of oil and gas quantities are generally not reflected in our individual property evaluations. COSTS Operating costs for the projects, leases, and wells in this report are based on the operating expense reports of CMS and 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. Operating costs include ad valorem taxes where applicable. Development costs were furnished to us by CMS and are based on authorizations 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. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage are significant. The estimates of the net abandonment costs furnished by Nomeco were accepted without independent verification. No deduction A-3 139 CMS Oil and Gas Company November 10, 2000 Page 4 was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. GENERAL Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 839 present our estimated projection of production and income by years beginning September 30, 2000, by country, state, field, and lease or well. The estimates of reserves presented herein were based upon a detailed study of the properties in which CMS owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities which may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. CMS has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by CMS were accepted without independent verification. The estimates presented in this report are based on data available, in general, through September 2000. CMS has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans. Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties. This report was prepared for the exclusive use of CMS Oil and Gas Company. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service. Very truly yours, RYDER SCOTT COMPANY, L.P. /s/ John R. Warner, P.E. John R. Warner, P.E. Senior Vice President JRW/sw A-4 140 HYDROCARBON PRICING PARAMETERS SEC PARAMETERS OIL AND CONDENSATE CMS furnished us with oil and condensate prices in for September 2000 and these prices were held constant to depletion of the properties. PLANT PRODUCTS CMS furnished us with plant product prices in effect for September 2000 and these prices were held constant to depletion of the properties. GAS CMS furnished us with gas prices in effect for September 2000 and with its forecasts of future gas prices which take into account SEC guidelines, current spot market prices, contract prices, and fixed and determinable price escalations where applicable. In accordance with SEC guidelines, the future gas prices used in this report make no allowances for future gas price increases which may occur as a result of inflation nor do they make any allowance for seasonal variations in gas prices which may cause future yearly average gas prices to be somewhat lower than December gas prices. For 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. 141 PETROLEUM RESERVES DEFINITIONS INTRODUCTION Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that Securities and Exchange Commission Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission. Reserves estimates will generally be revised as additional geologic or engineering data become available or as economic conditions change. Reserves do not include quantities of petroleum being held in inventory, and may be reduced for usage or processing losses if required for financial reporting. Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve. PROVED RESERVES (SEC DEFINITIONS) Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a) defines proved reserves as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when 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. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; 142 (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Certain Staff Accounting Bulletins published subsequent to the promulgation of Regulation S-X have dealt with matters relating to the application of financial accounting and disclosure rules for oil and gas producing activities. In particular, the following interpretations extracted from Staff Accounting Bulletins set forth the Commission staff's view on specific questions pertaining to proved oil and gas reserves. Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35) In determining whether "proved undeveloped reserves" encompass acreage on which fluid injection (or other improved recovery technique) is contemplated, is it appropriate to distinguish between (i) fluid injection used for pressure maintenance during the early life of a field and (ii) fluid injection used to effect secondary recovery when a field is in the late stages of depletion? . . . The Office of Engineering believes that the distinction identified in the above question may be appropriate in a few limited circumstances, such as in the case of certain fields in the North Sea. The staff will review estimates of proved reserves attributable to fluid injection in the light of the strength of the evidence presented by the registrant in support of a contention that enhanced recovery will be achieved. (extracted from SAB-35) Companies should report reserves of natural gas liquids which are net to their leasehold interest, i.e., that portion recovered in a processing plant and allocated to the leasehold interest. It may be appropriate in the case of natural gas liquids not clearly attributable to leasehold interests ownership to follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such reserves separately and describe the nature of the ownership. (extracted from SAB-35) 143 The staff believes that since coalbed methane gas can be recovered from coal in its natural and original location, it should be included in proved reserves, provided that it complies in all other respects with the definition of proved oil and gas reserves as specified in Rule 4-10(a)(2) including the requirement that methane production be economical at current prices, costs, (net of the tax credit) and existing operating conditions. (extracted from SAB-85) Statements in Staff Accounting Bulletins are not rules or interpretations of the Commission nor are they published as bearing the Commission's official approval; they represent interpretations and practices followed by the Division of Corporation Finance and the Office of the Chief Accountant in administering the disclosure requirements of the Federal securities laws. SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS) In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing. Producing. Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Non-Producing. Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. 144 [CMS OIL AND GAS LOGO] 145 PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION. The following is an itemized statement of the various expenses to be paid by the Registrant and the selling shareholder in connection with this offering. All amounts except the SEC registration fee, the NYSE listing fee and the NASD filing fee are estimated. These expenses will be borne by the Registrant and the selling shareholder based on the number of shares of common stock they are selling in proportion to the aggregate number of shares being sold in this offering. SEC registration fee....................................... $79,200 NYSE listing fee........................................... * NASD filing fee............................................ 30,500 Printing and engraving expenses............................ * Petroleum engineering fees and expenses.................... * Legal fees and expenses.................................... * Accounting fees and expenses............................... * Transfer agent and registrar fees and expenses............. * Miscellaneous.............................................. * ------- Total............................................ $ * =======

--------------- * To be completed by amendment. ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Sections 561 through 571 of the Michigan Business Corporation Act (the "MBCA") contain detailed provisions concerning the indemnification of directors and officers against judgments, penalties, fines and amounts paid in settlement of litigation. Article VII of the Registrant's Restated Articles of Incorporation reads: "A director shall not be personally liable to the corporation or its shareholders for monetary damages for breach of duty as a director except (i) for a breach of the director's duty of loyalty to the corporation or its shareholders, (ii) for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law, (iii) for a violation of Section 551(1) of the MBCA, and (iv) any transaction from which the director derived an improper personal benefit. If the MBCA is amended after approval by the shareholders of this Article VII to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director shall be eliminated or limited to the fullest extent permitted by the MBCA, as so amended. No amendment to or repeal of this Article VII, and no modification to its provisions by law, shall apply to, or have any effect upon, the liability or alleged liability of any director of the corporation for or with respect to any acts or omissions of such director occurring prior to such amendment, repeal or modification." Article VIII of the Registrant's Restated Articles of Incorporation reads: "Each director, officer, employee and agent of the corporation shall be indemnified by the corporation to the fullest extent permitted by law against expenses (including attorneys' fees), judgments, penalties, fines and amounts paid in settlement actually and reasonably incurred by him or her in connection with the defense of any proceeding in which he or she was or is a party or is threatened to be made a party by reason of being or having been a director, officer, employee and agent of the corporation or by reason of the fact that he or she is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, II-1 146 partnership, joint venture, trust or other enterprise. Such right of indemnification is not exclusive of any other rights to which such director, officer, employee and agent may be entitled under any now or hereafter existing statute, any other provision of these Articles, Bylaws, agreement, vote of shareholders or otherwise. If the MBCA is amended after approval by the shareholders of this Article VIII to authorize corporate action further eliminating or limiting the personal liability of directors, then the liability of a director of the corporation shall be eliminated or limited to the fullest extent permitted by the MBCA, as so amended. Any repeal or modification of this Article VIII by the shareholders of the corporation shall not adversely affect any right or protection of a director of the corporation existing at the time of such repeal or modification." Officers and directors are covered within specified monetary limits by insurance against certain losses arising from claims made by reason of their being directors or officers of the Registrant or of the Registrant's subsidiaries, and the Registrant's officers and directors are indemnified against such losses by reason of their being or having been directors of officers of another corporation, partnership, joint venture, trust or other enterprise at the Registrant's request. ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES. None. ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) Exhibits.

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II-3 148

--------------- * To be filed by amendment. (b) Financial Statement Schedule All financial statement schedules are omitted because they are not applicable or not required or because the required information is shown in the financial statements or notes thereto. ITEM 17. UNDERTAKINGS. (a) The undersigned Registrant hereby undertakes that: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (b) The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser. (c) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than II-4 149 the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. II-5 150 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on the 22nd day of November, 2000. CMS OIL AND GAS COMPANY By: /s/ WILLIAM H. STEPHENS III ---------------------------------- William H. Stephens III Executive Vice President, General Counsel and Secretary Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on the 22nd day of November, 2000.

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152

--------------- * To be filed by amendment.

CMS OIL & GAS CO S-1