10-K 1 o05424e10-k.txt FORM 10-K 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended DECEMBER 31, 2000 Commission File number 1-10216: CHIEFTAIN INTERNATIONAL, INC. (Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (780) 425-1950 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] The aggregate market value of the voting stock of Chieftain International, Inc. held by non-affiliates of said registrant on March 14, 2001 was US$408,903,378. The number of shares outstanding of the common stock of Chieftain International, Inc. on March 14, 2001 was 16,034,477. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Chieftain International, Inc. Information Circular dated April 4, 2001 for its annual and special meeting of shareholders to be held on May 17, 2001, are incorporated by reference into Part III hereof, to the extent indicated herein. The Exhibits Index can be found on page 55 of this document. This report contains forward-looking statements that are subject to risk factors associated with the oil and gas business. The Company believes that the expectations reflected in these statements are reasonable, but may be affected by a variety of factors including, but not limited to: price fluctuations, currency fluctuations, drilling and production results, imprecision of reserve estimates, loss of market, industry competition, environmental risks, political risks and capital restrictions. 2 CHIEFTAIN INTERNATIONAL, INC. 2000 FORM 10-K ANNUAL REPORT Table of Contents

3 PART I ITEM 1. BUSINESS We are an independent energy company engaged in the exploration, development and production of natural gas and oil. Our producing properties and exploration acreage are primarily located in the offshore US Gulf of Mexico. We also have properties located onshore in Louisiana, in the Four Corners area of southeast Utah and in the UK sector of the North Sea. We were incorporated under the Business Corporations Act (Alberta) in 1988 and commenced operations upon the closing of our initial public offering in April, 1989. We have a large natural gas and oil lease acreage position in the US Gulf of Mexico region. Our lease interests in the Gulf of Mexico region include a balanced portfolio of exploration and development drilling prospects. These prospects range from high-impact prospects with relatively greater risks, which we believe have the potential to add substantially to our natural gas and oil reserves, to relatively lower risk development and exploitation projects with lower reserve potential. Our exploration efforts are supported by an extensive 3D seismic database covering most of our leases. We believe that our seismic database and related technological expertise have contributed to our successful exploration and development record. We believe our conservative capital structure provides us with the financial flexibility to take advantage of our prospects and other opportunities, including acquisitions of leasehold acreage and producing properties. We hold interests in 141 lease blocks located on the continental shelf of the US Gulf of Mexico. We also have interests in 11 deep-water blocks. Of these lease blocks, 99 are held as exploratory acreage and 53 are held by production. We are operator of 45 of these blocks. Our average working interest in our US Gulf of Mexico leases is approximately 40%. In 2000 our production was 100.5 mmcfe per day (82.9 mmcfe per day after royalties) of which 78%, or 78.8 mmcfe per day (63.9 mmcfe per day after royalties), was in the US Gulf of Mexico. In addition to our US Gulf of Mexico properties, we own various interests in two large light oil producing units in the Four Corners area of southeast Utah where our production averaged 1,793 barrels per day (1,566 barrels per day after royalties) in 2000. We own an interest in approximately 8,300 net acres in the UK sector of the North Sea where our production averaged 5.4 mmcfe per day (before and after royalties) in 2000. We are also engaged in exploratory activities onshore in Louisiana. At December 31, 2000, we had estimated proved reserves of 326 bcfe (266 bcfe after royalties). These reserves had a present value of net cash flows before income taxes, discounted at 10%, of $1.2 billion using constant natural gas and oil prices in effect on December 31, 2000, which averaged $9.68 per mcf for US natural gas, $3.65 per mcf for UK natural gas and $24.60 per barrel for oil. At December 31, 2000, approximately 72% of our proved reserves were natural gas and approximately 59% of our proved reserves were developed. Our total proved reserves at December 31, 2000 had a reserve life index of approximately 8.9 years. SEGMENT INFORMATION Reference is made to pages 42 and 43 hereof for financial information with respect to our geographic segments for the years ended December 31, 2000, 1999 and 1998. ------------ * Unless the context indicates another meaning, the terms "we", "us" and "our" refer to Chieftain International, Inc. a company organized under the laws of the Province of Alberta, Canada, and its subsidiaries. For definitions of certain terms used throughout this report, see "Glossary". Our accounts are maintained, and all dollar amounts herein are stated, in United States Dollars unless otherwise indicated. 1 4 PROPERTIES Our principal natural gas and oil properties are in the US Gulf of Mexico and onshore Louisiana, Utah and other parts of the US and in the UK sector of the North Sea. The following table summarizes our estimated proved reserves by major operating area and the estimated present value of net cash flows before income taxes, discounted at 10%, of these reserves at December 31, 2000. The estimated present values reflect the US Securities and Exchange Commission required use of year-end prices, which at December 31, 2000 were $9.68 per mcf for US natural gas and $24.60 per barrel of oil.

US GULF OF MEXICO We concentrate our exploration and production activities in, and devote substantial managerial and financial resources to, the offshore US Gulf of Mexico. The Gulf of Mexico contains a prolific oil and natural gas basin. This area is more than 600 miles long and 100 miles wide and extends from the State of Texas to the State of Florida. Our exploration and development activities are focused primarily on the shallow waters (less than 600 feet deep) of the Gulf of Mexico Continental Shelf. The Continental Shelf is a low cost operating environment for which technical and analytical data, including 3D seismic data, are readily available. The vast network of gathering systems and pipelines in the shallow waters of the basin provides excellent access to markets. The Gulf of Mexico's geology is generally characterized by multiple productive horizons and good permeability which is conducive to high initial production and relatively rapid capital payback. We maintain a large acreage position in the US Gulf of Mexico. With an average interest of 40% in 152 blocks, we rank as one of the top ten independent leaseholders in the US Gulf of Mexico. Of these lease blocks, 141 are shallow water blocks and 11 are deep-water blocks. We acquired 11 blocks covering 55,696 acres at the March 2000 Central Gulf of Mexico lease sale. We acquired 3 blocks, covering 17,280 acres, at the Western Gulf of Mexico lease sale in late August 2000. Our acreage in the Gulf of Mexico covered 719,798 (285,598 net) acres at December 31, 2000. Of the 152 US Gulf of Mexico blocks in which we hold an interest, we are the designated operator of 45. Described below are the areas of our current exploration and development activity in the US Gulf of Mexico. WESTERN GULF (OFFSHORE TEXAS) MUSTANG ISLAND:

Most of our production in this area comes from our 50% working interest in Block 784. No significant exploration or development work is currently planned for 2001. 2 5 MATAGORDA ISLAND:

In 2000, we participated in one successful exploratory well and one successful development well on Block 704, in which we have a 25% working interest. Production commenced from these wells late in the fourth quarter. Numerous wireline, coiled tubing and rig recompletions are planned for the Matagorda Island area during 2001. We also expect to drill an exploratory well on Block 634 where we have a 24.1% working interest. HIGH ISLAND/EAST ADDITION/SOUTH EXTENSION:

During 2000, we participated in two unsuccessful exploratory wells in this area, both on Block 206. We had a 33.3% working interest in one well and a 25% working interest in the other. In 2001, we expect to participate in an exploratory well on each of Block 163, where we have a 30% working interest, Block 166, where we have a 33.3% working interest, and Block 348, where we have a 33.3% working interest. HIGH ISLAND SOUTH ADDITION:

During 2000, we participated in two successful exploratory wells, one successful development well and one unsuccessful exploratory well in this area. Late in the fourth quarter, a successful exploratory well was drilled from an existing production facility on Block A-467, where we have a 50% working interest. Production commenced in the first quarter of 2001. An exploratory well on Block A-554, where we have a 41.7% working interest, was drilled successfully in the fourth quarter and this natural gas discovery is expected to commence production during 2001. We are operator of Block A-531 where a development well encountered a commercial natural gas reservoir. The A-531Block, in which we have a 50% working interest, is expected to commence production during 2001 through a facility on the adjoining Block A-510, which we also operate and have a 50% working interest in. An exploratory well on Block A-567, where we have a 50% working interest, was junked and abandoned prior to reaching its geological objective and the drilling contractor did not earn there turnkey contract fee. In the second half of 2001, we expect to drill an exploratory well on Block A-567. GARDEN BANKS:

All of our production in this area currently comes from our 25% working interest in Block 224. We will be participating in an exploratory well in this deep water area during 2001. With a planned target depth of approximately 18,000 feet, the well could be drilled as early as the second quarter of 2001. It will test the Antigua prospect, located on Blocks 397 and 441. The water depth in the drilling area is approximately 2,500 feet. We have a 25% working interest in the project. 3 6 CENTRAL GULF (OFFSHORE LOUISIANA) EAST CAMERON:

In 2000, we participated in three successful exploratory wells in this area. Late in the fourth quarter, a natural gas well was drilled on Block 83, where we have a 25% working interest. Two natural gas wells were drilled on Block 104, where we have a 40% working interest. The Block 83 and Block 104 wells are expected to commence production during 2001. An exploratory well on Block 255, where we have a 60% working interest, and another on Block 369, where we have a 40% working interest, are planned for the second half and first half, respectively, of 2001. VERMILION:

During 2000, we participated in three exploratory wells in this area. Two successful wells, drilled on Block 267 where we have a 60% working interest, produce through a facility installed for a well drilled in 1999. A fourth quarter well on Block 263, where we have a 33.3% interest, was unsuccessful. An exploratory well on each of Block 16, where we have a 40% working interest, Block 23, where we have a 25% working interest, and Block 72, where we have a 100% working interest, are planned for the second half of 2001. SOUTH MARSH ISLAND:

In 2000, we participated in one exploratory well on Block 111, where we have a 25% working interest. The well did not find commercial reserves. During 2001, we expect to participate in three exploratory wells, all of which we will operate, and one development well. Two exploratory wells on Block 51, where we have a 60% working interest, and one exploratory well on Block 139, where we have a 100% working interest, will be drilled at approximately mid-year. The development well will be drilled on Block 39, where we have a 50% working interest. EUGENE ISLAND:

In 2000, our partner in Block 189 exchanged a 25% working interest for a 4% overriding royalty, bringing our working interest to 100%. A development well, which we began drilling early in 2001, if successful, will be produced along with two successful wells drilled previously from production facilities installed late in the fourth quarter of 2000. Production is expected to commence in 2001. In mid-2001, an exploratory well is planned for Block 355 where we have a 33.3% working interest. 4 7 SOUTH TIMBALIER:

In 2000, we participated in two exploratory wells in this area. A successful natural gas well was drilled on Block 250, where we have a 50% working interest, and production is expected to commence during 2001. Late in the year, a well drilled on Block 251, where we have a 50% working interest, did not find commercial reserves. WEST CAMERON:

In 2000, we participated in nine exploratory wells in this area, seven of which were successful. In the fourth quarter, a successful well on Block 192, where we have a 25% working interest, was drilled from an existing production facility and production began before year-end. We operate Block 300, where we have a 35% working interest, and where one of two wells drilled was successful. Block 300 commenced production in the fourth quarter. During the second half of the year, four successful natural gas wells were drilled on Block 370, where we have a 40% working interest. The Block 370 wells are expected to commence production during 2001. On Block 614, where we have a 25% working interest, a successful natural gas well was drilled and began producing late in the year along with the 1999 discovery on Block 613. On Block 386, where we have an 80% working interest, a second quarter well did not find commercial reserves. During 2001, we expect to participate in four exploratory wells, three of which we will operate, and three development wells. We will operate an exploratory well on each of Block 135 and Block 497, where we have 50% working interests. An exploratory well and two development wells will be drilled on Block 192, where we have a 25% working interest. A successful exploratory well was drilled in the first quarter of 2001, and a development well will be drilled in the second half of 2001, on Block 300, where we have a 35% working interest. The 2001 Block 300 exploratory well is expected to commence production in mid-2000. MAIN PASS:

In 2000, the Main Pass area continued to be one of the most significant contributors to our natural gas production. One development well on Block 223, where we have a 10% working interest, is currently planned for 2001. MISSISSIPPI CANYON:

We will participate in two exploratory wells in this deep-water area during 2001. The first well is planned for the west half of Block 29, where we have a 27% working interest. It will test the Schellhorn prospect at a planned target depth of approximately 10,000 to 12,500 feet in a water depth of approximately 2,000 feet. Drilling operations will utilize BP's Pompano subsea template. Should the well be successful, we expect to be able to complete it for production in 2001. The other exploratory well, with a planned depth of approximately 15,000 feet, will be drilled on Block 489, where we will have a 20% working interest. Drilling is expected to commence mid- year in a water depth of approximately 1,900 feet. 5 8 VERMILION PARISH, LOUISIANA NORTHEAST WRIGHT:

During 2000, we participated in one successful exploratory well and one successful development well in the Northeast Wright Field. Both the Langlinais #1 development well, in which we have a 50% working interest, and the Delahoussaye #2 exploratory well, in which we have a 1.8% working interest, commenced production during the summer of 2000. We expect to begin the drilling of a development well, Trahan #1, during the second half of 2001. FOUR CORNERS (PARADOX BASIN) AREA, UTAH ANETH UNIT:

RATHERFORD UNIT:

We have interests in two light oil fields where horizontal drilling has improved the effectiveness of a waterflood enhanced recovery program being employed in these fields. A pilot tertiary carbon dioxide recovery project in the Aneth Field has shown favorable results and is continuing. A similar project in the Ratherford Unit is under consideration for late 2001. NORTH SEA - UNITED KINGDOM SECTOR

All of our UK production comes from our interests in the Galahad Field, where we have a 17.8% working interest, and in the Mordred Field, where we have a 5.3% working interest. It is sold under 30-day contracts and in 2000 obtained an average price of $1.96 per mcf, net of transportation costs. The UK production is royalty free. Seismic work is planned to evaluate exploration ideas on our acreage in 2001. 6 9 ACREAGE The following table summarizes the developed and undeveloped acreage held by us as at December 31, 2000. Where applicable, interests which are not working interests (none of which is material) have been converted to working interest equivalents.

Our developed and undeveloped acreage in all areas covered 807,570 (305,463 net) acres at December 31, 2000. The undeveloped acreage, which has a cost to us of approximately $37 million, has not been independently evaluated. GAS AND OIL CAPITAL EXPENDITURES Reference is made to page 21 hereof for financial information with respect to our net capital expenditures for the years ended December 31, 2000, 1999 and 1998. 7 10 DRILLING ACTIVITY The following table summarizes the results of our drilling activities during the years ended December 31, 2000, 1999 and 1998.

WELLS Our productive gas and oil wells as at December 31, 2000 are listed in the following table. Any interests which are not working interests (none of which is material) have been converted to working interest equivalents.

RESERVES Our US natural gas and oil reserves have been evaluated by Netherland, Sewell & Associates, Inc. ("NS&A") and we have evaluated our UK reserves which amount to 1.9% (2.3% after royalties) of total equivalent reserves. For estimates of our proved and proved developed reserves see "Supplementary Financial Information". 8 11 PRODUCTION VOLUMES, PRICES AND COSTS Our net production of gas and oil (computed after royalty deductions but before production taxes) for the years ended December 31, 2000, 1999 and 1998 is listed below. Also listed are average sales prices and average production costs during such periods.

--------------- * Oil comprised approximately 82% (1999 - 89%; 1998 - 82%) of our oil and liquids production. EMPLOYEES At December 31, 2000, we had 44 full-time equivalent employees. In addition, we engage the services of consultants as required. BUSINESS RISKS If we cannot replace our reserves, our production and financial condition will suffer. Unless we successfully replace our reserves, our production will decline, resulting in lower revenues and cash flow. Replacing our reserves is particularly important because most of our reserves are in the US Gulf of Mexico where wells normally have steeper rates of decline than onshore wells. Reduced reserves may also make borrowing and raising equity more difficult. Furthermore, for the reasons discussed below, even if capital is spent on drilling or to make acquisitions, such efforts have a risk of being unsuccessful. Drilling wells is speculative and capital intensive. Exploring for oil and natural gas and developing oil and natural gas properties require significant capital expenditures and involve a high degree of financial risk. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise and supply tightens. Drilling may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells can hurt our efforts to replace reserves. Reserves on properties we buy may not meet our expectations and could change the nature of our business. Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property's production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and natural gas acreage without any warranty of title except through the transferor. In some instances, title opinions are not obtained if, in our judgment, it would be uneconomical or impractical to do so. Losses may result from title defects or from defects in the assignment of leasehold rights. While our current operations are primarily in shallow waters of the US Gulf of Mexico (offshore Texas and Louisiana), we may pursue acquisitions or properties located in other geographic areas, which would decrease our geographic concentration. 9 12 Estimates of our proved reserves are uncertain and our revenues from production may vary significantly from estimated amounts. The quantities and values of our proved reserves included in this Form 10-K are only estimates and are subject to numerous uncertainties. Estimates by other engineers might differ materially. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. These variances may be significant. Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserve reports. In addition, results of drilling, testing, production and changes in prices after the date of the estimate may result in substantial downward revisions. These estimates may not accurately predict the present value of net cash flows from oil and natural gas reserves. At December 31, 2000, approximately 41% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires additional capital expenditures and successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur. We do not insure against all potential losses and could be seriously harmed by unexpected liabilities. Exploration for and production of oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers' compensation laws in dealing with their employees. We maintain insurance against many potential losses and liabilities arising from our operations. However, in accordance with customary industry practice, we may not be fully insured against these risks, nor may all such risks be insurable. Compliance with governmental regulations is costly and complex, especially regulations relating to environmental protection. Our US exploration, production and marketing operations are regulated extensively at the federal, state and local levels. These regulations affect the costs, manner and feasibility of our operations. As an owner and operator of oil and natural gas properties, we are subject to federal, state and local regulation of discharge of materials into, and protection of, the environment. We have made and will continue to make significant expenditures in our efforts to comply with the requirements of these environmental regulations, which may impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damage and require suspension or cessation of operations in affected areas. Changes in, or additions to, regulations regarding the protection of the environment could increase our compliance costs and may negatively impact our business. We are subject to state and local regulations that impose permitting, reclamation, land use, conservation and other restrictions on our ability to drill and produce. These laws and regulations can require well and facility sites to be closed and reclaimed. We buy and sell interests in properties that have been operated in the past, and, as a result of these transactions, we may retain or assume clean-up or reclamation obligations for our own operations or those of third parties. US offshore oil and natural gas operations are subject to regulations of the United States Department of the Interior, which currently impose absolute liability upon the lessee under a federal lease for the cost of pollution clean-up resulting from the lessee's operations, and could subject the lessee to possible liability for pollution damage. In the event of a serious incident of pollution, a lessee under a federal lease may be required to suspend or cease operations in the affected area. In the UK, deposits of substances or articles at sea from offshore oil and natural gas operations are subject to the licensing control of the Ministry of Agriculture, Fisheries and Food. The breach of a license will result in criminal liability and possible civil liability for the cost of any resulting pollution clean-up. In the event of a serious incident of pollution, the Ministry may vary or revoke a license. We may have difficulty competing for oil and natural gas properties or supplies. We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties, as well as for the equipment, labor and materials required to develop and operate those properties. Many of these competitors have financial resources substantially greater than ours. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. 10 13 GLOSSARY The following are defined terms used herein: BCF means 1,000,000,000 cubic feet. BCFE means 1,000,000,000 cubic feet of natural gas equivalent. BLOCK refers to an offshore US Gulf of Mexico natural gas and oil lease. DEVELOPED ACREAGE refers to the number of acres assignable to productive wells. DEVELOPMENT WELLS are wells drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. DRY WELLS are wells found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as natural gas or oil wells. EXPLORATORY WELLS are wells drilled to find and produce natural gas or oil in an unproved area, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir, or to extend a known reservoir. GROSS ACRES means the total number of acres in which we own an interest. GROSS WELLS means the total number of wells in which we own an interest. LIQUIDS means natural gas liquids. MBBLS means 1,000 barrels. MCF means 1,000 cubic feet. MMCF means 1,000,000 cubic feet. MMCFE means 1,000,000 cubic feet of natural gas equivalent. NATURAL GAS RESERVES are reported at a base pressure of 14.65 psia and a base temperature of 60 degrees Fahrenheit. NATURAL GAS EQUIVALENT is determined by using the approximate energy equivalent ratio of 6 mcf of natural gas to 1 barrel of oil and liquids. NET ACRES refers to the sum of the fractional interests owned in gross acres. NET WELLS refers to the sum of the fractional interests owned in gross wells. NGLS means natural gas liquids. OIL or OIL AND LIQUIDS means crude oil and natural gas liquids. PRODUCTIVE WELLS are producing wells and wells capable of producing. PROVED DEVELOPED PRODUCING RESERVES are those reserves which are expected to be produced from existing completion intervals now open for production in existing wells. PROVED DEVELOPED NON-PRODUCING RESERVES are (1) those reserves expected to be produced from existing completion intervals in existing wells, but due to pending pipeline connections or other mechanical or contractual requirements hydrocarbon sales have not yet commenced, and (2) other non-producing reserves which exist behind the casing of existing wells, or at minor depths below the present bottom of such wells, which are expected to be produced through these wells in the predictable future, where the cost of making such oil and natural gas available for production should be relatively small compared to the cost of a new well. PROVED RESERVES are the estimated quantities of natural gas, crude oil and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves are limited to those quantities of natural gas and oil which can be expected, with little doubt, to be recoverable commercially at current prices and costs under existing regulatory practices and with existing conventional equipment and operating methods. PROVED UNDEVELOPED RESERVES are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. UNDEVELOPED ACREAGE is acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether or not such acreage contains proved reserves. WORKING INTEREST refers to the net interest held by us in an oil or natural gas lease or other disposition which interest bears its proportionate share of the costs of exploration, development and operations and any royalties or other production burdens. 11 14 ITEM 2. PROPERTIES Reference is made to Item 1, "Business", for information concerning our materially important physical properties. In addition, we lease office space. ITEM 3. LEGAL PROCEEDINGS We are, in the ordinary course of business, party to various legal proceedings. In the opinion of our management, none of these proceedings, either individually or in the aggregate, is material. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of our security holders during the fourth quarter of 2000. EXECUTIVE OFFICERS OF THE REGISTRANT The following table lists the name and age of each Executive Officer and all positions and offices held with us by each such person. The officers are appointed each year at the directors' meeting immediately following the annual meeting of the shareholders. The next such meeting will be held on May 17, 2001.

With the following exceptions, all of the officers have held their positions as officers since our incorporation in 1988, such position being his or her principal occupation. S.C. Hurley joined us in September, 1995 prior to which time he was the Vice President, Exploration of a US based integrated oil company. S.J. Milner and R.J. Stefure were appointed officers in June, 1995 and prior thereto held management positions with us. R.P. Boyd joined us in 1999 prior to which time he was Chief Financial Officer of a Canadian independent oil and gas company. There are no family relationships among the executive officers and directors except between S.A. Milner and D.E. Mitchell who are first cousins and between S.A. Milner and S.J. Milner who are father and son. 12 15 PART II ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED STOCKHOLDER MATTERS The principal United States market in which our Common Shares are traded is the American Stock Exchange. The Common Shares are also traded on the Toronto Stock Exchange. The high and low prices of our Common Shares (the "Common Shares") during each quarter since December 31, 1998 are shown below.

The Common Shares were held by 116 Shareholders of record on December 31, 2000. We estimate that investment dealers and other nominees hold Common Shares for approximately 2,200 beneficial holders. At the present time it is not our policy to declare regular dividends on the Common Shares. This policy is under periodic review by the Board of Directors and is subject to change at any time depending on our earnings and our financial requirements. Dividends may be paid on the Common Shares provided that all dividends on the preferred shares of Chieftain International Funding Corp. have been paid. All dividends on the preferred shares have been paid. 13 16 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA The selected consolidated financial and operating data for each of the five years ended December 31, 2000 has been derived from our consolidated financial statements included herein and should be read in conjunction with such consolidated financial statements and the related notes. SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARIES

14 17 Notes: (1) The use of US generally accepted accounting principles results in the following:

(2) This amount reflects write-downs in the carrying value of UK and Libyan gas and oil properties in 1999 and 1998 in accordance with full cost accounting rules under Canadian GAAP. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion and analysis in conjunction with our 2000 audited consolidated financial statements. The information contains forward-looking statements that are subject to risk factors associated with the oil and gas business. Forward-looking statements typically contain words such as "anticipate", "believe", "expect", "plan" or similar words suggesting future outcomes. We believe that the expectations reflected in these statements are reasonable, but may be affected by a variety of factors including, but not limited to: price and currency fluctuations, drilling and production results, imprecision of reserve estimates, loss of market, industry competition, environmental risks, political risks and capital restrictions. Our financial statements and information are reported in US dollars and are prepared based upon Canadian generally accepted accounting principles. Substantially all of our revenues and a significant portion of our operating expenses are realized or incurred in US dollars. For a discussion of the effect of differences in generally accepted accounting principles in Canada and the US on our financial statements, see Note 12 to our audited consolidated financial statements. For purposes of calculating unit costs, oil and ngls are converted to mcf equivalents at the rate of one barrel of oil per six thousand cubic feet of natural gas.

2000 OVERVIEW Strong natural gas and oil prices contributed to our record financial results in 2000. Revenues were $145.3 million ($119.9 million after royalties), net income applicable to common shares was $27.3 million, and cash flow from operations, after preferred share dividends, was $93.6 million. These amounts compare to revenues of $92.6 million ($76.4 million after royalties) in 1999 and $77.6 million ($64.4 million after royalties) in 1998, losses applicable to common shares of $11.8 million in 1999 and $ 9.1 million in 1998 and cash flow from operations of $50.1 million in 1999 and $37.8 million in 1998. Basic net income per common share was $1.69 in 2000 compared to losses of $0.86 per share in 1999 and $0.67 per share in 1998. 15 18 Our average natural gas price was $3.63 per mcf in 2000 compared to $2.02 per mcf in 1999 and $1.99 in 1998. Our combined average crude oil and ngls price was $27.72 per barrel in 2000 compared to $17.05 in 1999 and $11.74 in 1998. Net capital spending was $102.9 million in 2000 compared to $55.1 million in 1999 and $92.7 million in 1998. Three year finding and development costs for proved reserves were $1.17 per mcfe ($1.50 per mcfe after royalties) in 2000 compared to $1.15 per mcfe ($1.45 per mcfe after royalties) in 1999 and $1.51 per mcfe ($1.89 per mcfe after royalties) in 1998. We increased our proved reserves for the seventh consecutive year, adding 72.4 bcfe (56.2 bcfe after royalties), a reserve replacement rate of 197% (185% after royalties). Total proved reserves increased to 326 bcfe (266 bcfe after royalties). At December 31, 2000, our proved reserves had a present value of future net cash flows before income taxes, discounted at 10%, of $1.2 billion (1999 - $267 million; 1998 - $153 million). These values reflect the required use of year-end prices, which at December 31, 2000 were $9.68 per mcf for US natural gas and $24.60 per barrel of oil. Production in 2000 averaged 100.5 mmcfe per day (82.9 mmcfe per day after royalties) compared to 112.9 mmcfe per day (93.4 mmcfe per day after royalties) in 1999 and 103.2 mmcfe per day (85.2 mmcfe per day after royalties) in 1998. New production from eight properties was added during 2000, primarily during the second half of the year. Production commenced from three of these properties in December. As a result of this additional production, our exit rate at December 31, 2000 was 121.6 mmcfe per day (99.5 mmcfe per day after royalties). PRODUCTION

Our average combined natural gas and oil production rate decreased by 11% to 100.5 mmcfe per day (82.9 mmcfe per day after royalties) in 2000 from 112.9 mmcfe per day (93.4 mmcfe per day after royalties) in 1999 and 103.2 mmcfe per day (85.2 mmcfe per day after royalties) in 1998. Natural gas comprised 76% (75% after royalties) of our production volumes in both 2000 and 1999, and 80% (79% after royalties) in 1998. In 2000, natural gas production was 28.0 bcf (22.9 bcf after royalties) compared to 31.1 bcf (25.5 bcf after royalties) in 1999 and 30.0 bcf (24.5 bcf after royalties) in 1998. In 2000, oil and natural gas liquids production was 1.5 mmbbls (1.2 mmbbls after royalties) compared to 1.7 mmbbls (1.4 mmbbls after royalties) in 1999 and 1.3 mmbbls (1.1 mmbbls after royalties) in 1998. Comparing 2000 and 1999, average production rates decreased 7.4 mmcfe per day (5.5 mmcfe per day after royalties) in the US and 4.6 mmcfe per day (before and after royalties) in the UK. During 2000, US production volumes decreased compared to 1999 as a result of the concentration of production from new properties in the second half of the year. The majority of the successful wells drilled in 1999 and scheduled for development in 2000 experienced delays in both follow-up drilling and facilities design and installation, causing a greater than expected time lag in production additions. The decline in production was halted in the second quarter, and production grew through the remainder of the year. In the UK, where no further exploration and development is currently planned, production is subject to normal decline. Comparing 1999 and 1998, production growth was primarily from properties in the US Gulf of Mexico region which produced for the first time in 1999. Ninety-two percent of 2000 natural gas production came from our interests in 121 wells in the US Gulf of Mexico region compared to 88% (111 wells) in 1999 and 89% (108 wells) in 1998. Fifty-four percent of our 2000 and 1999 oil and ngls production came from our holdings in the US Gulf of Mexico region (1998 - 28%). 16 19 NATURAL GAS AND OIL MARKETING Ninety-six percent of our natural gas reserves are located in the US Gulf of Mexico region where ready deliverability through numerous large capacity pipelines and auxiliary feeder pipelines provides flexibility in marketing our production. Natural gas prices in the US and in the UK are largely determined by competitive market forces. Most of the natural gas produced by us, as well as our US Gulf of Mexico region oil and natural gas liquids production, has been marketed since 1989 by Highland Energy Company, an aggregator for several natural gas producers. Our oil production from the Aneth and Ratherford Units in the Four Corners area of Utah is sold under successive term contracts to a regional refiner since 1989. Due to its quantity and quality, we have obtained premiums over locally posted prices for this production. Market prices of oil and natural gas fluctuate and can materially affect our operating results. We sell most of our natural gas under short term contractual arrangements and do not engage in speculative forward selling of volumes that cannot be physically delivered. To mitigate some of this price risk, we may enter into forward sales for a portion of our production so as to lock in a firm natural gas price for a specific volume and delivery period. At December 31, 2000, we had entered into forward sales for the physical delivery, during the first nine months of 2001, of natural gas production totaling 7.1 bcf (approximately 15% of our forecast 2001 equivalent volume), at an average price, net of transportation, of $4.86 per mcf. At the 1999 year-end, we had entered into forward sales for the physical delivery of 2000 natural gas production of 6.1 bcf (approximately 17% of our 2000 equivalent volume) at an average price of $2.49 per mcf. Forward sales of natural gas at December 31, 1998 were immaterial. Also at December 31, 1999, we had entered into oil forward sales for the physical delivery of 90 mbbls of 2000 production at an average price of $19.00 per barrel. We had not entered into oil forward sales at either December 31, 2000 or 1998. NATURAL GAS Our composite average natural gas price was $3.63 per mcf in 2000 compared to $2.02 in 1999 and $1.99 in 1998. The mild North American winter of 1998-1999 had a downward effect on 1998 US natural gas prices. During the first quarter of 1999, we received an average of $1.54 per mcf for our US natural gas. Thereafter, prices increased to an average of $2.39 per mcf in the fourth quarter of 1999. Strong demand for electricity, as well as the demand associated with replenishing storage for the forthcoming 2000-2001 winter, pulled our US natural gas price from $2.51 per mcf in the first quarter of 2000 to $3.18 per mcf and $3.84 per mcf in the second and third quarters, respectively. During the fourth quarter of 2000, the benchmark New York Mercantile Exchange natural gas futures experienced significant volatility. This is reflected in the $5.20 per mcf price realized in the fourth quarter of 2000 for our US production. For the full year 2000, our average US natural gas price was $3.76 per mcf (1999 - $2.16 per mcf; 1998 - $2.06 per mcf) and our average UK natural gas price was $1.96 per mcf (1999 - $0.96 per mcf; 1998 - $1.40 per mcf). OIL AND NGLS Our average oil and ngls price per barrel was $27.72 in 2000 compared to $17.05 in 1999 and $11.74 in 1998. In 1998, the combination of economic problems in Asia, the mild North American winter and international competition for market share caused oil prices to fall. Oil prices began to recover when, in the second quarter of 1999, Organization of Petroleum Exporting Countries' ("OPEC") production quotas became effective. Starting with the first quarter of 1999, we experienced seven consecutive quarters of increasing oil and ngls prices before they leveled out at a price of $30.32 per barrel in the fourth quarter of 2000. REVENUE In 2000, an 80% increase in natural gas prices was complemented by a 63% increase in oil prices. Increased prices more than offset decreased production with the result that our 2000 production revenue increased 56% from 1999 to $142.4 million ($117.0 million after royalties). In 1999, growth in our combined natural gas and oil production volumes was accompanied by a recovery in commodity prices. As a result, 1999 production revenues increased 22% from 1998 to $91.5 million ($75.4 million after royalties).

17 20

ROYALTIES Royalties include payments made to federal and state governments, freehold land owners and other third parties. Our US Gulf of Mexico properties in US federal waters generally carry a 16-2/3% royalty rate. Some of these properties carry overriding royalties ranging from 1.1% to 10%. In 2000, the effective average overriding royalty rate was 1.9% (1999 - 2.2%; 1998 - 2.7%). Production from the Aneth and Ratherford Units is subject to production taxes and to a 12.5% royalty. The Aneth unit carries an additional royalty burden of approximately 2%. The Northeast Wright Field, in Louisiana, is subject to a 26% royalty. The UK properties carry no royalty obligations. As the UK properties mature, natural production declines will reduce the proportion of this production in our mix and our composite royalty per mcfe can be expected to increase. WE PAY NO OVERRIDING ROYALTIES TO MANAGEMENT OR STAFF.

INTEREST AND OTHER REVENUE Interest and other revenue for 2000 included non-recurring revenue of $1.3 million arising from the Libyan venture which was terminated in the second quarter of 1999. Under the terms of the concession, the Libyan National Oil Company ("NOC") reimbursed us and our partners in kind for NOC's share of production test expenditures. The non-recurring revenue resulted from the increase in oil prices between the time when production test expenditures were incurred and the time when reimbursement was effected. In 1998, interest and other revenue included a non-recurring court award of $1.6 million pursuant to a successful claim for recovery of excess transportation charges incurred from 1990 through 1997. EXPENSES PRODUCTION COSTS Our aggregate production costs in 2000 decreased 2% compared to 1999. However, because production taxes increased 43% to $2.0 million and production volumes were lower, our per unit production costs increased. Our production costs in 1999 decreased 12% from 1998, a result of non-recurring items in 1998 and the termination of the Libyan production test in mid-1999. Production costs for US Gulf of Mexico region properties were $0.28 per mcfe ($0.35 per mcfe after royalties) in 2000 compared to $0.25 per mcfe ($0.31 per mcfe after royalties) in 1999 and $0.32 per mcfe ($0.41 per mcfe after royalties) in 1998. Production costs for the Aneth and Ratherford Units, which are primarily oil producing properties where secondary and tertiary recovery methods are being used, were $1.28 per mcfe ($1.47 per mcfe after royalties) in 2000 compared to $1.15 per mcfe ($1.32 per mcfe after royalties) in 1999 and $0.99 per mcfe ($1.13 per mcfe after royalties) in 1998. 18 21

Production from the Aneth and Ratherford Units and the Northeast Wright and Chacahoula Fields in Louisiana is subject to production and severance taxes. As a result of the price dependent methodologies used to calculate these taxes, and the anticipated additional production from the D. W. Guidry # 1 well in the Northeast Wright Field, we expect that our production taxes will increase in 2001. GENERAL AND ADMINISTRATIVE Our general and administrative costs increased 31% in 2000 compared to 1999 and decreased 5% in 1999 compared to 1998. Performance-based compensation payments were higher in 2000 than in 1999 and lower in 1999 than in 1998. Also contributing to higher costs in 2000 were the hiring of three professional employees required in support of our larger role as an operator, non-recurring legal fees and increased office costs.

INTEREST Interest expense decreased to $1.1 million in 2000 from $2.5 million in 1999 and $0.4 million in 1998. The fluctuations were largely due to varying credit facility utilization. Our weighted average debt outstanding during 2000 was $15.2 million compared to $42.1 million in 1999 and $12.3 million in 1998. The effective interest rate on our outstanding debt for 2000 was 7.32% compared to 5.93% in 1999 and 6.19% in 1998. The interest rate on our debt at December 31, 2000 was 7.63%. DEPLETION AND AMORTIZATION Depletion and amortization expense in 2000 decreased by $7.6 million, compared to 1999, of which $5.5 million related to the decrease in production and $2.1 million related to the decrease in the average depletion rate to $1.19 per mcfe ($1.44 per mcfe after royalties). Our lower finding and development costs for proved reserves in 1999, the oil price induced upward revision in our proved reserves and the ceiling test write-down of UK properties contributed to the decrease in our depletion rate in 2000. Comparing 1999 to 1998, depletion and amortization expense increased $9.3 million, of which $4.0 million related to the increase in production and $5.3 million related to the increase in the average depletion rate to $1.25 per mcfe ($1.51 per mcfe after royalties). The downward revision in our proved reserves at December 31, 1998, the result of low oil prices at that date, contributed to the increase in our 1999 depletion rate. We expect that our depletion rate will be approximately $1.35 per mcfe ($1.64 per mcfe after royalties) in the first quarter of 2001. The depletion rate is reviewed quarterly. 19 22 Accounting rules require that we review regularly, on a country-by-country basis, the carrying value of our oil and gas properties for possible write-down or impairment. Under these rules, capitalized costs of proved reserves are not allowed to exceed the value of estimated future net revenues from those proved reserves (the "ceiling test"). Full cost accounting rules allow, but do not require, companies to exclude costs of acquiring and evaluating unproved properties from their depletion cost centers, but if such costs are excluded, they must be separately assessed for impairment. Our policy on depletion does not exclude such costs from their respective depletion cost centers. The Canadian full cost accounting guideline was revised during 2000 to require that a ceiling test must be conducted on a quarterly basis. We will prospectively apply this policy effective with the first quarter of 2001. In Libya, we and our partners concluded that the multi-year exploration program, and the production test which commenced in December 1997, were not commercially viable under the terms of the concession and therefore terminated the venture. As a result, additional depletion of $11.4 million was recorded in the second quarter of 1999 to eliminate the investment. An impairment provision of $5.1 million was recorded at December 31, 1998 in respect of one of the Libyan concessions upon which no further exploration was then planned. In respect of the UK properties, we recorded ceiling test impairments at December 31, 1999 and 1998 due to very low spot market prices for natural gas and downward reserve revisions, respectively. TAXES We have available $230.3 million in US tax pools and $29.1 million in Canadian tax pools to reduce future taxable income. Should natural gas and oil prices remain at recent levels, we will be required to pay current income taxes in 2001 as follows: - US Alternative Minimum Tax ("AMT"), the amounts of which are, for us, dependent upon tax loss utilization, and which can be carried forward and credited against regular tax in future years; and - UK corporate income taxes, the amounts of which will depend primarily on UK natural gas prices, and for which we receive limited double-taxation relief both in Canada and the US. During 2000, both the Canadian Federal and Alberta Provincial governments proposed corporate income tax rate reductions. As our deferred tax asset arises in Canada, lower corporate income tax rates reduce the future value of the tax asset. If the proposed rate reductions are all enacted the tax rate for our Canadian taxable income would fall to 30.12% in 2005, a reduction of about one-third compared to the 44.62% rate in 2000. The Canadian Federal rate reductions were substantially enacted in 2000 and we have recorded the effect, a $1.3 million expense, in 2000. The proposed Alberta rate reductions did not satisfy the requirements for recognition in 2000. We expect that the Alberta rate reductions will be substantially enacted in 2001, at which time we will record their effect, an estimated expense of $1.3 million, thereby reducing the carrying amount of the deferred tax asset. NET INCOME (LOSS) APPLICABLE TO COMMON SHARES In 2000, income before provision for dividends on preferred shares of a subsidiary increased $39.2 million to $32.3 million compared to 1999. After provision of $4.9 million for dividends on preferred shares of a subsidiary, net income applicable to common shares for 2000 was $27.3 million, an improvement of $39.2 million compared to 1999. The most significant factors responsible for the improvement were the increased natural gas and oil prices in 2000 and the non-recurring nature of the 1999 write-off of the Libyan investment. In 1999, the loss applicable to common shares, after provision of $4.9 million for dividends on preferred shares of a subsidiary, in 1999 was $11.8 million, $2.7 million more than in 1998. Improved prices and increased production volumes realized in 1999 were more than offset by regular and additional depletion charges. 20 23 CAPITAL EXPENDITURES Natural resource capital expenditures were $102.7 million in 2000 compared to $55.0 million in 1999 and $92.6 million in 1998.

LAND AND LEASE HOLDINGS We acquired leases in two lease sales during 2000. We participated in high bids for 14 blocks, 5 as operator, covering 72,890 acres (33,684 net acres). Our share of the bids on the blocks, all of which have been awarded, was $4.3 million. At December 31, 2000, we had an average working interest of 40% in 152 offshore blocks covering 719,798 gross acres compared to an average working interest of 40% in 139 blocks covering 661,410 gross acres a year earlier. DRILLING RESULTS Drilling in all areas, including extensive development drilling in the Utah oil producing units in 1998, resulted in success rates of 63% in 2000, 70% in 1999 and 84% in 1998. In 2000, our exploratory drilling success rate in the US Gulf of Mexico region was 59% compared to 73% in 1999 and 43% in 1998. Including development wells, our success rate in the region was 63% in 2000 compared to 78% in 1999 and 58% in 1998.

21 24 In addition to the wells described above, at December 31, 2000 we had an interest in one (0.67 net) well which was drilling. At December 31, 1999 we had interests in three (0.62 net) wells which were drilling and one (0.50 net) well which was being evaluated. No wells were being drilled or evaluated at December 31, 1998. Three wells were drilled in 2000 on our leases in the US Gulf of Mexico region at no cost to us; two are natural gas wells and one was being evaluated at year-end. In 1999, five wells were drilled on our acreage in the region at no cost to us; one resulted in a natural gas well and four were unsuccessful. In 1998, one successful natural gas well was drilled on our acreage at no cost to us. CAPITAL FIELD DEVELOPMENT ACTIVITY During 2000, design, construction and/or installation of production facilities and pipelines, which are the components of our capital field development, totaled $25.9 million and were principally at Eugene Island 189, High Island A-510/A-531, High Island A-530, Matagorda Island 704, South Timbalier 196, Vermilion 267, West Cameron 300 and West Cameron 613/614 where production facilities and, except at Eugene Island 189 and High Island A-510/A-531, pipelines, were installed. Onshore, facilities were completed for the Langlinais #1 well in the Northeast Wright Field and at Chacahoula. FINDING AND DEVELOPMENT COSTS COST OF RESERVE ADDITIONS Three year finding and development costs of proved reserves were $1.17 per mcfe ($1.50 per mcfe after royalties). The upward pressure on exploration service and supply costs is the primary reason for the increase from the 1999 three year finding and development cost of $1.15 per mcfe ($1.45 per mcfe after royalties). The 1998 three year finding and development costs were $1.51 per mcfe ($1.89 per mcfe after royalties). In calculating finding costs, a number of anomalies between periods are created by the timing of expenditures and the phase of the exploration and production cycle. This relates particularly to lease acquisitions and to major facility construction, as well as to recognition and revision of reserves. Multi-year cumulative average calculations are a more meaningful reflection of a company's ability to find and produce reserves. Finding costs are calculated by dividing capital expenditures for a period by proved reserve additions (before production) for the same period. Both a three-year calculation and one year components are included in the following table.

RESERVE REPLACEMENT For the seventh consecutive year, we added more proved reserves than we produced with total proved reserves increasing to 326 bcfe (266 bcfe after royalties). The increase of 72.4 bcfe (56.2 bcfe after royalties), before production, results in a reserve replacement rate of 197% (185% after royalties). 22 25 RESERVES Reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers, as to our US reserves and internally as to our UK reserves, contain estimates of our total proved reserves, before and after royalty deductions, as described below. UK reserves comprise 1.9% (2.3% after royalties) of our total proved reserves on a bcfe basis.

Reserve life indexes are calculated by dividing year-end reserve volumes by the year's production volumes

23 26 NET FUTURE CAPITAL EXPENDITURES The reserve reports incorporate estimated future capital expenditures, 89% of which will be spent over the next five years, that are required to bring proved undeveloped reserves to production, to maintain proved producing reserves, and to provide for future abandonment.

RESERVE VALUE RECONCILIATION As required by the Financial Accounting Standards Board Statement 69, our reserves were estimated using year-end prices which, at December 31, 2000, were $24.60 per barrel for oil and $9.68 per mcf for US natural gas. The resulting estimated present values of proved reserves are not considered to be estimates of fair market value. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF THIS INFORMATION.

CAPITAL RESOURCES AND LIQUIDITY Our primary sources of cash are funds generated from operations and financing activities. Our primary cash outflows are for exploration and development activities. Cash flow from operations, a frequently used measure of performance for exploration and production companies, is derived by adjusting net income (loss) attributable to common shares to eliminate the effects of depletion and amortization, additional depletion, write-down of marketable securities and deferred income taxes. We generated cash flow from operations of $93.6 million in 2000 compared to $50.1 million in 1999 and $37.8 million in 1998. The variances are primarily a function of fluctuating revenues caused by the volatility of commodity prices. 24 27

In 1997, a third party sold its interests in producing properties that we currently operate and since that time neither the vendor nor the purchaser has reimbursed us on a timely basis for expenditures made by us, as operator, for their account. Accordingly, we commenced an action in the Louisiana courts against both the vendor and the purchaser to recover the amounts currently owing to us, approximately $4.6 million, plus interest and costs. Although the purchaser filed for Chapter 11 bankruptcy in the first half of 2000, we currently expect to recover all current and future amounts outstanding and have therefore made no allowance for doubtful collectability. Our financing activities in 2000 provided $6.7 million of cash, the net result of: - the drawdown of $10 million of our revolving credit facility; - the exercise of employee share options for $1.6 million; and - the purchase for cancellation of 228,600 common shares for $4.9 million under a share repurchase program which expires on August 14, 2001. Our financing activities in 1999 provided $16.2 million of cash, the net result of: - the sale of 2,875,000 common shares for $46.3 million, net of issue costs; - the net repayment of $30 million of our revolving credit facility; and - the purchase for cancellation of 7,500 common shares for $0.1 million under a share repurchase program which expired on November 1, 1999. Financing activities during 1998 provided $34.5 million of cash, the net result of: - the drawdown of $40 million of our revolving credit facility; - the exercise of employee share options for $0.4 million; and - the purchase for cancellation of 294,700 common shares for $5.9 million under a share repurchase program. Cash used in natural resource investing activities increased to $102.7 million for 2000 compared to $55.0 million and $92.6 million for 1999 and 1998, respectively. The components of our natural resource investing activities are as follows:

25 28 Early in the fourth quarter of 2000, we purchased $5 million of marketable securities. A $1.1 million write-down of the marketable securities, to a carrying amount approximating their fair value, was recorded at December 31, 2000. Concurrent with the purchase of these shares, we entered into an agreement giving us an option to acquire Qatari petroleum and natural gas interests. Early in 2001, the option expired, unexercised. Our December 31, 2000 cash balance was $8.7 million (1999 - $19.4 million; 1998 - $10.6 million). We had outstanding borrowings of $20 million on our revolving bank credit facility at December 31, 2000 (1999 - $10 million; 1998 - $40 million). During the third quarter of 2000, our revolving bank credit facility was reduced to $70 million upon the withdrawal from the syndicate of one lender for reasons unrelated to us. The original amount of the facility was $100 million. With no immediate need for the $30 million difference, we have decided to not pursue an immediate replacement for the withdrawn syndicate member. The weighted average interest rate on our borrowings for 2000 was 7.32% (1999 - 5.93%; 1998 - 6.19%). RISK ASSESSMENT There are a number of risks facing the oil and gas industry. Some are common to all businesses while others are industry specific. The following review includes our approach to managing various risks. OPERATIONAL RISKS Exploration for and production of oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, can result in the injury or death of people, and can damage property and the environment. We seek to mitigate the foregoing risks by maintaining prudent levels of insurance against many potential losses and liabilities arising from our operations. However, in accordance with customary industry practice, we may not be fully insured against these risks, nor may all such risks be insurable. Unless we successfully replace our reserves, our production will decline, resulting in lower revenues and cash flow. Replacing our reserves is particularly important because most of our reserves are in the US Gulf of Mexico where wells normally have steeper rates of decline than onshore wells. Exploring for oil and natural gas and developing oil and natural gas properties require significant capital expenditures and involve a high degree of financial risk. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when rig supply tightens and drilling costs rise. Drilling may be unsuccessful for many reasons, including the inherent imprecision of geological interpretation, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells can harm our efforts to replace reserves. We seek to limit our financial and operating risks in some projects by participating in drilling with industry partners and operators. We believe this strategy limits our risk exposure, particularly in high potential prospects. We also seek to operate projects in which we participate in order to better control costs and timing. Additionally, we have increasingly relied on advanced technologies, including 3D seismic analysis, to define geologic risks, thereby enhancing the results of our drilling efforts. ENVIRONMENTAL AND SAFETY RISKS US exploration, production and marketing operations are regulated extensively at the federal, state and local levels. These regulations affect costs, manner and feasibility of our operations. Changes in, or additions to, regulations regarding the protection of the environment could increase our compliance costs and may negatively affect our business. US offshore oil and gas operations are subject to regulations of the US Department of the Interior which currently imposes absolute liability upon the lessee under a federal lease for the cost of pollution clean-up resulting from the lessee's operations, and could subject the lessee to possible liability for pollution damage. In the UK, deposits of substances or articles at sea from offshore oil and gas operations are subject to the licensing control of the Ministry of Agriculture, Fisheries and Food. At present, we believe that our properties are being operated in compliance with applicable environmental laws and regulations. We do not anticipate that we will be required in the foreseeable future to expend amounts that are unusual, in relation to customary industry experience, by reason of environmental laws and regulations, but we are unable to quantify the ultimate cost of compliance. 26 29 MARKETING RISKS There is uncertainty as to the prices at which gas and oil we produce may be sold, and it is possible that under some market conditions the production of gas and oil from some of our properties may not be commercially viable. The availability of a ready market for gas and oil as produced and the price obtained for such gas and oil depend upon numerous factors beyond our control, including market considerations, the proximity and capacity of gas and oil pipelines and processing equipment and governmental regulation. In recent years, markets for natural gas in the US have been characterized by periods of unbalanced supply and demand. There have been significant fluctuations in prices for both gas and oil in recent years and there can be no assurance that prices for gas or oil will not decrease in the future. Prices for oil and natural gas are volatile and declined significantly during the second half of 1998 and early 1999. The recovery in prices, which started in 1999, continued through 2000, as did price volatility. Natural gas prices affect us more than oil prices as natural gas was 76% (75% after royalties) of our 2000 and 1999 energy equivalent production and 80% (79% after royalties) of our 1998 energy equivalent production. Primarily because of lower prices, we recorded ceiling test write-downs of the UK assets in 1999 and 1998. Most of the factors which affect natural gas and oil prices are beyond our control, such as demand, worldwide economic conditions, weather conditions, supply levels, import prices, political conditions in major oil producing regions, especially the Middle East, and actions taken by the OPEC. We could be required to write down the carrying value of our natural gas and oil properties in the future if natural gas and oil prices are depressed for even a short period of time, are unusually volatile or if we have substantial downward revisions to our proved reserve quantities. Any such ceiling test write-down would result in a charge to earnings and a reduction of shareholders' equity, but would not affect our cash flow from operating activities. Once incurred, these write-downs cannot be reversed at a later date. CORPORATE GOVERNANCE The Board of Directors and management of the Company support the guidelines for corporate governance set forth by the Toronto Stock Exchange and the Company's corporate governance practices were developed in accordance with these guidelines. THE BOARD'S MANDATE The Board of Directors exercises overall responsibility for the management and supervision of the Company's affairs. It has established processes, policies and practices to guide its stewardship of the Company in the areas of strategic planning; identification and management of the principal risks of the Company's business; succession planning and management development; communications; and internal control and management information. Management is responsible for providing information and maintaining processes which enable the Board to discharge its responsibilities. Administrative procedures govern the approval of transactions, the delegation of authority and the signing of documents. The Board of Directors is kept informed of the Company's operations through regularly scheduled meetings of the Board and its committees and through reports and analyses and discussions with management. During 2000, the directors met at four regularly scheduled meetings. Two additional meeting were held by telephone conference. Communications between the directors and management occur as required in addition to the board and committee meetings. The Board of Directors annually reviews and approves the Company's corporate strategy. The Board reviews the Company's budget for the following fiscal year, including operating and financial targets and approves the capital expenditures for which management is responsible. As part of that process, the objectives of the Chief Executive Officer and the Chief Operating Officer are reviewed. Management performance, succession planning and management development are regularly reviewed by the Compensation Committee and in turn by the Board of Directors . The Company's communications strategy and implementation is regularly reviewed by the Board of Directors and the Board is informed of communication activities. In addition to the Annual Meeting, the Company participates in conferences and quarterly conference calls. The Company's transfer agent, CIBC Mellon Trust Company has a toll-free number (1-800-387-0825) to assist shareholders. The Board and appropriate Committees review the Company's Annual Report to Shareholders, Management's Discussion and Analysis, Management Information Circular, Annual Information Form, Form 10-K Annual Report, quarterly financial statements, Interim Reports, Form 10-Q Reports and news releases on major developments before they are distributed. The Company provides information on its business and financial results on its internet site at www.chieftaininternational.com. 27 30 News releases and other prescribed documents are available on the electronic databases mandated by the Securities and Exchange Commission known as "EDGAR" (www.sec.gov/) and by Canadian Securities Authorities known as "SEDAR" (www.sedar.com). THE BOARD'S COMPOSITION The Board of Directors is comprised of eight members. Having regard to the size and complexity of the Company's business, the Board considers that eight is the minimum number of directors required. The Board of Directors is constituted with a majority of individuals who are independent, unrelated directors. Three senior officers of the Company are members of the Board. The Chairman of the Board is a non-executive Chairman who has not held another office with the Company. The Board meets at least annually with only the independent, unrelated members in attendance. COMMITTEES OF THE BOARD The Board of Directors has five committees, as follows. Each of the committees has four members and all committees are comprised entirely of independent, unrelated directors. Committees may engage external resources. Audit Committee The primary function of the Audit Committee is to assist the Board of Directors in providing corporate oversight in the areas of financial reporting, internal control and the audit process. The Committee regularly meets alone with Company personnel and with the independent auditors. The independent auditors have access to the Committee at any time. The Committee reviews and recommends to the Board for its approval the annual financial statements and is also responsible for reviewing interim unaudited financial statements prior to their release. The Committee reviews and recommends the annual appointment, terms of engagement and proposed fees of the independent auditors. Compensation Committee The primary function of the Compensation Committee is to assist the Board of Directors in carrying out its responsibilities by reviewing compensation matters and making recommendations to the Board. It considers and provides recommendations to the Board on directors' compensation, appointment and remuneration of officers and grants of share options. This Committee reviews compensation and benefits policies, plans and budgets; salaries of certain non-officer employees; results based compensation; and succession planning. Nominating and Corporate Governance Committee The Nominating and Corporate Governance Committee assists the Board by reviewing corporate governance and Board nomination matters and making recommendations to the Board as appropriate. The Committee advises the Board on such matters as the size and composition of the Board of Directors and its committees, nominees for the election of directors and corporate governance practices. Pension Committee The Pension Committee reviews and makes recommendations to the Board of Directors with regard to the Company's retirement plans, related agreements, the appointment and performance of retirement fund investment managers, and compliance with the plans' statements of investment policies. Reserve Committee The primary function of the Reserve Committee is to review the Company's externally disclosed oil and natural gas reserve estimates. The Committee reviews the reports of the independent engineers charged with evaluating the Company's reserves and also reviews the selection and qualifications of the independent engineers, the scope of their work and the evaluation procedures used. OUTLOOK AND PROSPECTS FOR FUTURE GROWTH OUR STRATEGY Our strategy is to increase our reserves, production, revenue and cash flow through exploration and development drilling and through the acquisition of leasehold acreage and producing properties. The elements of our strategy include the following: - Focus on the US Gulf of Mexico region. We focus our operations on the US Gulf of Mexico region where we have acquired a significant exploration acreage position and assembled a substantial 3D seismic database. We believe this region combines significant geological potential, reservoir size, quality and deliverability with favorable commodity pricing and attractive finding, development and operating costs. 28 31 - Grow through exploration. We are pursuing an active technology-driven exploration program that is designed to balance projects with lower risk and moderate potential with drilling prospects which have higher risk and substantial potential. We generate exploration prospects through geological and geophysical analysis of 3D seismic and other data and also review prospects generated by others. Our Board of Directors has approved a 2001 budget of $105 million for exploration and development capital expenditures and we expect to use approximately $65 million of this amount for exploration activities. We are currently drilling or plan to drill approximately 36 gross exploratory and development wells in the US Gulf of Mexico region in 2001. Approximately three-quarters of these will be exploratory wells and the remainder are development wells to follow up previous discoveries. - Manage drilling risks through joint ventures and the use of advanced technologies. This element of our strategy is described under Operational Risks on page 26. - Evaluate and pursue strategic acquisitions. We continually review opportunities to acquire leasehold acreage and producing properties. We seek to acquire properties that we believe have significant exploration potential and to increase our working interests in producing lease blocks when available to us on economically favorable terms. OUR STRENGTHS We believe that our future performance and historical success are directly related to the following combination of strengths: - Financial capability and flexibility. At December 31, 2000, $50 million was available under our unsecured revolving credit facility. We seek to maintain low levels of debt in order to be able to respond quickly to drilling or acquisition opportunities. - Substantial inventory of drilling projects in the US Gulf of Mexico region. In the US Gulf of Mexico region, we continue to generate, and maintain, a two year inventory of drilling prospects. All of these locations have been evaluated and defined using 3D seismic data. Our large inventory permits us to be flexible in project selection and in the timing of drilling. By identifying new exploration targets and acquiring additional acreage, we continually add to our drilling inventory. - Proven exploratory expertise. Our ability to define and participate in successful prospects in the US Gulf of Mexico is demonstrated by our three year exploratory drilling success rate in the US Gulf of Mexico region of 58%. - Experienced technical team. Our technical team is comprised of highly respected industry professionals with an average of more than 20 years of industry experience. Our exploration success is a direct result of this team's geologic, geophysical, engineering and technical analysis. OUR LOOK FORWARD The fundamentals for US natural gas marketing remain positive. The US Energy Information Administration ("EIA") reports that US natural gas demand increased by 3.7% during 2000. For 2001, the EIA forecasts that consumption will be 23.35 trillion cubic feet, an increase of 3% from 2000 levels, even though it expects wellhead natural gas prices to average $5.22 per mcf. The strong demand for electricity continues to increase the requirement for natural gas-fired generation. This, combined with the competing demand for natural gas to refill storage, should support continued price strength. At year-end 2000, the American Gas Association reported that storage volumes were 23% lower than the comparative average for 1996-1998 and 29% lower than at year-end 1999. On the natural gas supply side, low commodity prices in 1998 and 1999 dramatically reduced drilling. This downturn limited domestic production to 18.6 trillion cubic feet in 2000, an increase of less than 1% from 1999. The EIA is forecasting that increased drilling activity will support a 5.3% increase in domestic production in 2001. The active rig count in the US declined by 24% in 1999 to average 625 active rigs compared to 827 in 1998, according to Baker Hughes. In comparison, the active rig count increased 47% to average 918 in 2000 and had increased to 1,128 by the third week of January 2001. This increased level of activity reflects the recovery in commodity prices. The experience of 2000 confirmed the earlier conclusion of many industry observers that the natural gas supply and demand equation was tightening up in the US. The balancing of natural gas supply and demand will continue to confer benefits on properly poised companies in our industry. We believe that adherence to our strategy will bring continued growth, and maintain a strong balance sheet which will, in turn, allow us to be opportunistic and to grow, during periods of both low and high prices. Our current 2001 exploration and development budget, which we plan to fund from operating cash flow, is expected to increase 2001 production volumes to 125 mmcfe per day, 24% above 2000 levels. In 2001, we will benefit from the commencement of production from a number of new offshore facilities. 29 32 Our capital expenditures can vary significantly with exploration results, availability of equipment and services and opportunities. We will continue to monitor capital spending and adjust investment levels in relation to cash flow projections. If reductions were required to be made to our budgeted 2001 capital expenditures, economic merit and a longer term view would be used to make such decisions. Specifically, fewer wildcat wells could be drilled (either delayed or deleted), bidding at lease sales could be curtailed and seismic data acquisition could be reduced. If our budgeted 2001 capital expenditures were to be increased, for reasons other than cost overruns or expenditures contingent on successful drilling, great care would be taken to ensure that our associated human resources would be adequate. The nature of such increased capital expenditures would be dependent upon the opportunities that arise. Our long-term growth is dependent upon our ability to effectively reinvest cash flow. While increased production volumes will improve cash flow, oil and natural gas prices will have the most significant effect on cash flow levels. Our view of natural gas prices in the US Gulf of Mexico region remains optimistic. We believe that the control on oil prices that can be exerted by OPEC has been amply demonstrated over the past few years. Should OPEC continue to adhere to its production quotas, we expect that WTI prices well in excess of $20 per barrel will continue to prevail. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The following consolidated financial statements of Chieftain International, Inc. and the management's and auditors' reports thereon are included herein. The financial statements are in US dollars. Management's Report Auditors' Report Consolidated Balance Sheet as at December 31, 2000 and 1999 Consolidated Statement of Income (Loss) and Deficit for the years ended December 31, 2000, 1999 and 1998 Consolidated Statement of Cash Flows for the years ended December 31, 2000, 1999 and 1998 Notes to Consolidated Financial Statements Supplementary Financial Information (Unaudited) 30 33 MANAGEMENT'S REPORT The accompanying consolidated financial statements and all information in this annual report are the responsibility of management. The financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. The financial information contained elsewhere in this annual report is consistent with the consolidated financial statements in all material respects. The Company maintains accounting systems and internal controls to provide reasonable assurance that its financial information is reliable and accurate, and that its assets are adequately safeguarded. Where necessary, management has made informed judgments and estimates in the preparation of the financial statements. Independent auditors, appointed by the shareholders, have examined the consolidated financial statements. The Audit Committee of the Board of Directors meets periodically with management and the independent auditors to review audit, internal control, accounting policy and financial reporting matters. The annual consolidated financial statements are approved by the Board of Directors on the recommendation of the Audit Committee. /s/ S. A. Milner /s/ R. J. Stefure ------------------------------------- ---------------------------------------- S.A. Milner R.J. Stefure President and Chief Executive Officer Vice President and Controller February 1, 2001 31 34 AUDITORS' REPORT We have audited the consolidated balance sheets of Chieftain International, Inc. as at December 31, 2000 and 1999 and the consolidated statements of income (loss) and deficit and cash flows for each of the years in the three-year period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian and United States generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2000 and 1999 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2000 in accordance with Canadian generally accepted accounting principles. /s/ PricewaterhouseCoopers LLP ---------------------------------------- Chartered Accountants Edmonton, Alberta February 1, 2001 32 35 CONSOLIDATED BALANCE SHEET Chieftain International, Inc. and Subsidiary Companies

Approved by the Board: /s/ S. A. Milner /s/ L. G. Munin ----------------------------------- ---------------------------------------- S.A. Milner, Director L.G. Munin, Director 33 36 CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT Chieftain International, Inc. and Subsidiary Companies

34 37 CONSOLIDATED STATEMENT OF CASH FLOWS Chieftain International, Inc. and Subsidiary Companies

35 38 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (DECEMBER 31, 2000, 1999 AND 1998) CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES * We are engaged in natural gas and oil exploration, development and production primarily in the United States ("US") and also in the United Kingdom ("UK") sector of the North Sea. The Consolidated Financial Statements are expressed in US currency as most of our assets and operations are denominated in US dollars. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a) ACCOUNTING PRINCIPLES Our financial statements are prepared in conformity with Canadian generally accepted accounting principles. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make informed judgements and estimates. Actual results may differ from those estimates. Material differences between Canadian and US accounting principles that affect us are referred to in Note 12, which provides the effects of the differences on earnings and balance sheet accounts. (b) PRINCIPLES OF CONSOLIDATION The Consolidated Financial Statements include our accounts and the accounts of our subsidiary companies, all of which are wholly-owned except for Chieftain International Funding Corp., a US subsidiary which in 1992 issued 2,726,700 preferred shares to the public. These preferred shares are convertible into common shares of Chieftain International, Inc. See Note 4. Acquisitions of subsidiaries and businesses have been accounted for by the purchase method and accordingly only income or losses since date of acquisition are included in the Consolidated Statement of Income (Loss) and Deficit. (c) MARKETABLE SECURITIES Our interest in marketable securities is accounted for by the cost method. Application of the cost method results in the investment initially being recorded at cost and earnings therefrom are recognized only to the extent that dividends are received or are receivable. The amount of the investment is reduced by any dividends received in excess of our pro rata share of post-acquisition income. (d) FOREIGN CURRENCY TRANSLATION Canadian and other foreign currency amounts have been translated into US currency on the following bases: monetary assets and liabilities at the year-end rates of exchange; non-monetary assets and liabilities at historical exchange rates; and revenue and expenses at monthly average exchange rates during the year. Translation gains or losses are reflected in the Consolidated Statement of Income (Loss) and Deficit. (e) FINANCIAL ASSETS AND LIABILITIES Our financial instruments that are included in the Consolidated Balance Sheet are comprised of cash and short-term deposits, accounts receivable, marketable securities, all current liabilities and long-term debt. In each case, their fair value approximates the carrying amount reflecting their short-term or current rate nature. Cash and short-term deposits include minimum risk certificates guaranteed by a major Canadian bank and are purchased three months or less from maturity. Accounts receivable are subject to normal oil and natural gas industry credit risks. Marketable securities are subject to currency, market and liquidity risks: the shares trade in Canadian currency, share prices are volatile and timely divestiture may not be possible at share prices approximating fair value. Long-term debt is subject to normal floating interest rate risk. ----------- * Unless the context indicates another meaning, the terms "we", "us" and "our" refer to Chieftain International, Inc., a company organized under the laws of the Province of Alberta, Canada, and its subsidiaries. 36 39 (f) NATURAL RESOURCE PROPERTIES We account for natural gas and oil properties in accordance with the Canadian guideline on full cost accounting. Under this method, all costs associated with the acquisition, exploration and development of natural gas and oil properties are capitalized in cost centers on a country-by-country basis. Depletion is calculated using the unit-of-production method based on gross proved reserves (before royalties) and combining oil and natural gas on an energy equivalent basis, using the ratio of 1 barrel of oil = 6,000 cubic feet of natural gas. Future well abandonment and site restoration costs are included in the calculation of depletion expense and are based on current engineering estimates in accordance with current regulations and industry practices. Actual costs, when incurred, are charged against the abandonment cost accrual. A ceiling test is applied to ensure that capitalized costs do not exceed estimated future net revenues less certain applicable costs. See Note 2. (g) LAND, BUILDINGS AND OTHER EQUIPMENT Amortization is provided as follows:

Expenditures for renewals and betterments which materially increase the estimated useful life of buildings and equipment are capitalized; expenditures for repairs and maintenance are charged to income. Costs and accumulated amortization of assets retired or sold are removed from the asset and related accumulated amortization accounts; losses and gains thereon are included in the Consolidated Statement of Income (Loss) and Deficit as depletion and amortization. (h) INCOME TAXES Income taxes are recorded using the liability method of accounting. Applying this method, deferred income taxes are recognized, using applicable, enacted, or substantively enacted, income tax rates, for future income tax consequences attributable to differences between the financial statement carrying values and their respective income tax bases. The effect of a change in tax rates on deferred income tax assets and liabilities is included in income in the period that includes the enactment date. Deferred income tax assets are evaluated and if realization is considered "more likely than not", no valuation allowance is provided. (i) PER SHARE AMOUNTS Effective with the fourth quarter of 2000, we retroactively adopted revised per share calculation methods which are required to be adopted no later than 2001 under Canadian generally accepted accounting principles. Consistent with the revision, we now include share options in diluted per share amounts, where dilutive, assuming that the share options are exercised using the treasury stock method. The retroactive application of this policy had the effects of increasing our diluted income per common share by $0.05 in 2000. All relevant amounts for prior periods have been restated for consistency and comparability. 2. NATURAL RESOURCE PROPERTIES The following weighted average December 31 field prices were used in the determination of our US future net revenues for purposes of the ceiling test:

A field price of $3.65 (1999 - $0.99; 1998 - $1.74) per mcf was used in the determination of our UK future net revenues for purposes of the ceiling test. There is uncertainty as to the prices at which natural gas and oil produced by us may be sold in the future. 37 40 The application of the ceiling test to US property carrying costs at December 31, 1998, using the $12.27 per barrel average oil and natural gas liquids ("ngls") price received by us during the year and the $2.15 per mcf December 31, 1998 natural gas price, required no write-down. At December 31, 1998, a write-down of $10,614,000, after providing for tax recoveries of $5,842,000, would have been required had prices as of that date, $2.15 per mcf for natural gas and $9.72 per barrel for oil and ngls, been used. At December 31, 1999 an impairment provision of $6,310,000 (1998 - $2,849,000), after providing for tax recoveries of $5,083,000 (1998 - $2,295,000), was recorded in respect of the Libyan concessions which resulted in all Libyan costs being written off as of that date. At December 31, 1999, a write-down of $2,654,000 (1998 - $609,000), after providing for tax recoveries of $2,139,000 (1998 - $491,000), was recorded in respect of the UK properties. Depletion rates per physical unit of US production are as follows:

The depletion rate per physical unit of UK natural gas production was $0.51 per mcf for the year ended December 31, 2000 (1999 - $1.24; 1998 - $0.81). At December 31, 1998, Libyan property carrying costs of $9.9 million were excluded from depletion calculations pending evaluation. General and administrative costs relating directly to lease acquisition, exploration and development activities have been capitalized as follows:

3. REVOLVING CREDIT AND LONG-TERM DEBT In 1997 we arranged an unsecured revolving credit facility with a syndicate of banks. The facility, in the amount of $70 million (1999 - $100 million)or the Canadian dollar equivalent, is fully revolving for 364 day periods with extensions at the option of the lenders upon our request. If not extended, the facility converts to term loans repayable over a period not exceeding four years. Advances under the facility bear interest at Canadian prime rate, US base rate, Bankers' Acceptance rate or LIBOR plus applicable margins. Certain financial tests are required to be met quarterly. Under this facility, $20 million was utilized at December 31, 2000 (1999 - $10 million), carrying a weighted average interest rate of 7.63% (1999 - 7.00%). 4. PREFERRED SHARES OF A SUBSIDIARY Chieftain International Funding Corp. ("Funding"), a subsidiary of Chieftain International (U.S.) Inc., sold 2,726,700 shares of $1.8125 cumulative convertible redeemable preferred shares at $25.00 per share in a 1992 public offering in the US. The preferred shares are redeemable, at the option of Funding, at $25.2014 per share during 2001 and $25.00 per share after December 31, 2001, plus accumulated and unpaid dividends. Each preferred share has a liquidation preference of $25.00 and is convertible at any time into 1.25 Common Shares of Chieftain International, Inc. at the option of the holder. 38 41 5. SHARE CAPITAL (a) COMMON SHARES

* Pursuant to normal course issuer bid. ** Reduced by costs of issue of $4,058, less related deferred taxes of $1,811. In the fourth quarter of 1999, we sold 2,875,000 common shares by way of a public offering in the US at $17.50 per share. (b) COMMON SHARES RESERVED At December 31, 2000, 1,394,632 (1999 - 1,130,207; 1998 - 1,130,875) of our authorized but unissued common shares were reserved for issuance under the Share Option Plan. See Note 5(d). We have reserved 3,408,375 common shares for issuance pursuant to the conversion provisions of the preferred shares of a subsidiary. See Note 4. (c) CONTRIBUTED SURPLUS Contributed surplus represents the excess of original net issue price over purchase price of shares purchased and cancelled pursuant to successive issuer bids. (d) SHARE OPTION PLAN (THE "PLAN") The Plan provides for the granting of options to employees, directors and consultants to purchase our common shares. Each option expires not later than ten years from the date it was granted. Options are exercisable as to one-third of the granted amount on or after each of the first three anniversaries of the date of grant. The option price for shares in respect of which an option is granted under the Plan is not less than the market price on the date of grant and, therefore, no compensation expense is recognized. Proceeds arising from the exercise of share options are credited to share capital. At December 31, 2000 options were outstanding to 60 participants in the Plan. The following is a summary of activity related to the Plan for the years ended December 31, 2000, 1999 and 1998.

39 42 The following table summarizes information about options outstanding at December 31, 2000.

6. INTEREST AND OTHER REVENUE Interest and other revenue for 2000 included non-recurring revenue of $1.3 million arising from the Libyan venture which was terminated in the second quarter of 1999. Under the terms of the concession, the Libyan National Oil Company ("NOC") reimbursed us and our partners in kind for NOC's share of production test expenditures. The non-recurring revenue resulted from the increase in oil prices between the time when production test expenditures were incurred and the time when reimbursement was effected. In 1998, interest and other revenue included $1.6 million awarded by the courts pursuant to a successful claim for recovery of excess transportation charges incurred from 1990 through 1997. The award comprises transportation charges, legal fees and judgement interest of $1,129,000, $282,000 and $189,000, respectively. 7. INCOME TAXES Income tax expense is made up of the following components:

40 43 The actual tax rate differs from the expected tax rate for the following reasons:

Temporary differences comprising the deferred tax assets (liabilities) are as follows:

At December 31, 2000 our net operating tax losses carried forward are summarized in the following table. We are of the opinion that the tax benefit of these tax losses will be realized.

41 44 8. PER SHARE AMOUNTS Basic net income (loss) per common share is calculated by dividing net income (loss) applicable to common shares by the weighted average number of common shares outstanding during the year. Diluted income (loss) per common share is calculated to give effect to share options and shares issuable on conversion of preferred shares.

9. SUPPLEMENTAL CASH FLOW INFORMATION Net cash outflows for (inflows from) income taxes were $211,000, $(12,000) and $14,000 for the years 2000, 1999 and 1998, respectively. Cash outflows for long-term debt interest were $1,032,000, $2,601,000 and $628,000 in 2000, 1999 and 1998, respectively. 10. PENSION COSTS AND OBLIGATIONS We contributed $178,416, $145,418 and $145,300 for 2000, 1999 and 1998, respectively, to defined contribution pension plans. Under a supplementary defined contribution pension plan established in 1991, costs of $209,484, $216,401 and $198,294 for 2000, 1999 and 1998, respectively, and the related liability are recorded in the accounts. We have established no other post-employment benefit plans. 11. SEGMENTED INFORMATION We have a single reportable segment with activities as explained in the preamble to the Notes. Production revenue, after royalties, all of which arises from external customers, is attributed to the country in which the underlying production occurred. Most of the US natural gas, oil and ngls we produce are marketed by a single aggregator. Production revenues, after royalties, associated with the aggregator were $90,842,000 (1999 - $59,665,000; 1998 - $46,340,000). As at December 31, 2000, we had entered into natural gas forward contracts with the aggregator. The forward contracts are for the physical delivery of, during the first nine months of the following year, natural gas volumes totalling 7.1 billion cubic feet ("bcf") (1999 - 6.1 bcf), at an average price of $4.86 per mcf (1999 - $2.49 per mcf). Our oil production from the Aneth and Ratherford Units in the Four Corners area of Utah is sold under successive term contracts to a regional refiner. Production revenues, after royalties, associated with sales to the regional refiner were $14,188,000 (1999 - $9,710,000; 1998 - $8,207,000). At December 31, 1999, we had entered into an oil forward contract with the regional refiner for the physical delivery, in 2000, of oil volumes of 90,000 barrels at an average price of $19.00 per barrel. We believe that alternative marketing arrangements would be readily available for our natural gas, oil and ngls. 42 45

12. US ACCOUNTING PRINCIPLES (a) FULL COST ACCOUNTING US full cost accounting rules differ materially from the Canadian full cost accounting guidelines we follow. In determining the limitation on carrying values, US rules require the discounting of future net revenues at 10%, and Canadian guidelines require the use of undiscounted future net revenues and the deduction of estimated future administrative and financing costs. During 1999 and 1998, impairment adjustments would have been required under US accounting rules. The quarterly test required by US accounting rules, using a March 31, 1999 UK natural gas price of $0.84 per mcf to determine future net revenues, would have resulted in a write-down of UK property carrying costs at March 31, 1999 of $7.1 million and, after providing for tax recoveries of $3.1 million, a net charge to operations of $4.0 million. Using December 31, 1998 US natural gas and oil prices of $2.15 per mcf and $9.72 per barrel to determine future net revenues would have resulted in a write-down of US property carrying costs of $65.5 million and, after providing for tax recoveries of $22.9 million, a net charge to operations of $42.6 million at December 31, 1998. Using June 30, 1998 US prices of $2.09 per mcf and $12.40 per barrel to determine future net revenues would have resulted in a write-down of US property carrying costs of $24.7 million and, after providing for tax recoveries of $8.6 million, a net charge to operations of $16.1 million at June 30, 1998. Such write-downs would result in reduced depletion expense, under US rules, for subsequent periods. In 1999, under Canadian guidelines the test resulted in a write-down of UK property carrying costs of $4.8 million (1998 - $1.1 million) and, after providing for tax recoveries of $2.1 million (1998 - $0.5 million), a net charge to operations of $2.7 million (1998 - $0.6 million) at December 31; no corresponding write-downs were required under US accounting rules. 43 46 (b) EFFECT ON EARNINGS The effect on consolidated earnings of the differences between Canadian and US accounting principles is summarized as follows:

(c) EFFECT ON BALANCE SHEET The effect on the Consolidated Balance Sheet of the differences between Canadian and US accounting principles is as follows:

Additionally for US reporting purposes, the preferred shares shown as shareholders' equity in these consolidated financial statements would be shown outside the equity section. (d) INCOME TAX DISCLOSURES Provisions for deferred income taxes are as follows:

44 47 The provision for income taxes differs from the amount of income tax determined by applying the Canadian statutory rate to pre-tax income before dividends paid on preferred shares of a subsidiary, as a result of the following:

Temporary differences comprising the deferred tax assets (liabilities) are as follows:

(e) STOCK-BASED COMPENSATION We apply the intrinsic value method prescribed by APB Opinion 25 and related interpretations in accounting for share option transactions. Accordingly, no compensation cost is recognized in the accounts. US accounting principles require disclosure of the impact on earnings and earnings per share of the value of options granted after 1994, calculated in accordance with FAS 123. 45 48 Such impact, using fair values of $11.38, $7.75 and $10.61 for options granted in 2000, 1999 and 1998, respectively, would approximate the following pro forma amounts.

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions for grants as follows:

(f) RECENT ACCOUNTING PRONOUNCEMENTS FAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by FAS 138, is first effective for our 2001 fiscal year. FAS 133 currently has no affect on us as our derivative instruments qualify for the normal purchases and normal sales exception. 46 49 SUPPLEMENTARY FINANCIAL INFORMATION CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES DECEMBER 31, 2000 (Unaudited) RESERVE INFORMATION Reports prepared by Netherland, Sewell & Associates, Inc. as to our US reserves and by ourselves as to the UK reserves, estimate the total proved reserves owned by us, before and after royalty deductions, as follows:

* 19,100 (1999 - 20,100) barrels of natural gas liquids, before and after royalty deductions, associated with the UK gas reserves are not included in this table. 47 50 (Unaudited)

RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES

48 51 (Unaudited) CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES

COSTS INCURRED IN GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES

49 52 (Unaudited) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THERE IN RELATING TO PROVED OIL, NATURAL GAS LIQUIDS AND NATURAL GAS RESERVES The following standardized measure of discounted future net cash flow was computed in accordance with Financial Accounting Standards Board Statement 69 using year-end prices and costs, and year-end statutory tax rates. Royalty deductions were based on laws, regulations and contracts existing at the end of each period. No values are given to unproved properties or to probable reserves that may be recovered from proved properties. The inexactness associated with estimating reserve quantities, future production streams and future development and production expenditures, together with the assumptions applied in valuing future production, substantially diminish the reliability of this data. The values so derived are not considered to be estimates of fair market value. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF THIS INFORMATION.

50 53 (Unaudited) The following table sets out principal sources of change in the standardized measure of discounted future net cash flows during the respective periods.

51 54 (Unaudited) Quarterly Information

* Restated to reflect retroactive application of treasury stock method when assessing share options for dilutive effect. 52 55 (Unaudited) Quarterly Information

53 56 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no disagreements between us and our auditors on accounting or financial disclosure matters. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS Additional information relating to our directors is incorporated herein by reference from page 6 of our Information Circular dated April 4, 2001 for the annual and special meeting of shareholders on May 17, 2001. ITEM 11. EXECUTIVE COMPENSATION "Executive Compensation" on pages 6 to 10 of our Information Circular dated April 4, 2001 for the annual and special meeting of shareholders on May 17, 2001 is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT "Voting Shares" and "Share Ownership" on pages 3 and 4 of our Information Circular dated April 4, 2001 for the annual and special meeting of shareholders on May 17, 2001 is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K The following is a listing of the financial statements and financial statement schedules which are included in this Form 10-K report. FINANCIAL STATEMENTS Reference is made to the list of financial statements on page 30 of this report. EXHIBITS Reference is made to the Index to Exhibits on page 55 of this report. 54 57 Index to Exhibits

* Previously filed as an exhibit to the Registration Statement on Form S-1, File No. 33-27254. ** Previously filed as an exhibit to the Registration Statement on Form S-1/S-3, File No. 33-51630. *** Previously filed as an exhibit to Form 8-K dated March 1, 1994. **** Previously filed as an exhibit to Form 10-K dated March 20, 1998. ***** Filed herewith. ****** Previously filed as an exhibit to Form 10-K dated March 17, 1994. ******* To be filed. 55 58 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CHIEFTAIN INTERNATIONAL, INC. By: /s/ STANLEY A. MILNER ------------------------------------- Stanley A. Milner, A.O.E., LL.D. President and Chief Executive Officer Principal Executive and Financial Officer Dated: March 14, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated. /s/ D.E. MITCHELL Director March 14, 2001 ---------------------------------- D.E. Mitchell O.C. /s/ S.A. MILNER President, Chief Executive Officer and March 14, 2001 ---------------------------------- S.A. Milner, A.O.E., LL.D. Director; Principal Executive and Financial Officer /s/ S.C. HURLEY Director March 14, 2001 ---------------------------------- S.C. Hurley /s/ H.J. KELLY Director March 14, 2001 ---------------------------------- H.J. Kelly /s/ J.E. MAYBIN Director March 14, 2001 ---------------------------------- J.E. Maybin /s/ L.G. MUNIN Director March 14, 2001 ---------------------------------- L.G. Munin /s/ E.S. ONDRACK Director March 14, 2001 ---------------------------------- E.S. Ondrack /s/ S.T. PEELER Director March 14, 2001 ---------------------------------- S.T. Peeler /s/ R.J. STEFURE Vice President and Controller March 14, 2001 ---------------------------------- R.J. Stefure Principal Accounting Officer

CHIEFTAIN INTERNATIONAL INC 10-K