IVANHOE ENERGY INC - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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FORM 10-K

(Mark One)

[X] Annual Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934. For the fiscal year ended
December 31, 2001.
or
[ ] Transition Report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934. For the transition period
from ------------------------------ to
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Commission file number 000-30586

IVANHOE ENERGY INC.
(Exact name of registrant as specified in its charter)

YUKON, CANADA
(State or other jurisdiction of
incorporation or organization)

NOT APPLICABLE
(I.R.S. Employer
Identification No.)

654 -- 999 CANADA PLACE
VANCOUVER, BRITISH COLUMBIA, CANADA
V6C 3E1
(Address of principal executive offices)

(604) 688-8323
(Registrant's telephone number, including area code)

Securities to be registered pursuant to Section 12(b) of the Act: None

Securities registered or to be registered pursuant to Section 12(g) of the Act:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
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Common Shares, no par value The Toronto Stock Exchange
NASDAQ National Market

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 [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

The aggregate market value of the voting stock held by non-affiliates of the
Registrant on March 1, 2002 based on the closing price on the NASDAQ National
Market on that date, was $279,035,000.

Documents incorporated by reference: None
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TABLE OF CONTENTS

2

CURRENCY AND EXCHANGE RATES

Unless otherwise specified, all reference to "dollars" or to "$" are to United
States dollars and all references to "Cdn.$" are to Canadian dollars. The
closing, low, high and noon buying rates in New York for cable transfers for the
conversion of Canadian dollars into United States dollars for each of the four
years ended December 31, 2001 as reported by the Federal Reserve Bank of New
York were as follows:

The average noon rate of exchange reported by the Federal Reserve Bank of New
York for conversion of United States dollars into Canadian dollars on March 1,
2002 was $0.6278 ($1.00 = Cdn.$1.5929). Exchange rates are based upon the noon
buying rate in New York City for cable transfers in foreign currencies as
certified for customs purposes by the Federal Reserve Bank of New York.

ABBREVIATIONS

As generally used in the oil and gas business and in this Annual Report, the
following terms have the following meanings:

BOE = barrel of oil equivalent
BBL = barrel
MBBL = thousand barrels
MMBBL = million barrels
BBL/D = barrels per day
MBBL/D = thousand barrels per day
MMBL/D = million barrels per day
MMBTU = million British thermal units
MCF = thousand cubic feet
MMCF = million cubic feet
MCF/D = thousand cubic feet per day
MMCF/D = million cubic feet per day

When we refer to oil in "equivalents," we are doing so to compare quantities of
oil with quantities of gas or to express these different commodities in a common
unit. In calculating Bbl equivalents, we use a generally recognized standard in
which one Bbl is equal to six Mcf.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements in this document are "forward-looking statements". Such
forward-looking statements involve known and unknown risks, uncertainties and
other factors which may cause our actual results, performance or achievements,
or other future events, to be materially different from any future results,
performance or achievements or other events expressly or implicitly predicted by
such forward-looking statements. Such risks, uncertainties and other factors
include, but are not limited to, our short history of limited revenue, losses
and negative cash flow from our current exploration and development operations
in the United States and China; our limited cash resources and consequent need
for additional financing; uncertainties regarding the potential success of our
oil and gas exploration and development projects in the United States and China;
uncertainties regarding the potential success of gas-to-liquids technology; oil
price volatility; oil and gas industry operational hazards and environmental
concerns; government regulation and requirements for permits and licenses,
particularly in the foreign jurisdictions in which we carry on business; title
matters; risks associated with carrying on business in foreign jurisdictions;
conflicts of interests; competition for a limited number of promising oil and
gas exploration properties from larger more well financed oil and gas companies;
and other statements contained herein regarding matters that are not historical
facts. Forward-looking statements can often be identified by the use of
forward-looking terminology such as "may", "will", "expect", "intend",
"estimate", "anticipate", "believe" or "continue" or the negative thereof or
variations thereon or similar terminology.

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ENFORCEABILITY OF CIVIL LIABILITIES

We have been organized under the laws of Canada and our executive offices are
located in British Columbia, Canada. Some of our directors, controlling persons
and officers and representatives of the experts named in this Form 10-K Annual
Report reside outside the United States and a substantial portion of their
assets and our assets are located outside the United States. As a result, it may
be difficult for you to effect service of process within the United States upon
the directors, controlling persons, officers and representatives of experts who
are not residents of the United States or to enforce against them judgments
obtained in the courts of the United States based upon the civil liability
provisions of the federal securities laws or other laws of the United States.
There is doubt as to the enforceability in Canada against us or against any of
our directors, controlling persons, officers or experts who are not residents of
the United States, in original actions or in actions for enforcement of
judgments of United States courts, of liabilities based solely upon civil
liability provisions of the U.S. federal securities laws. Therefore it may not
be possible to enforce those actions against us, our directors and officers or
experts named in this Form 10-K Annual Report.

RISK FACTORS

We are subject to a number of risks due to the nature of the industry in which
we operate, the present state of development of our business and the foreign
jurisdictions in which we carry on business. The following factors contain
certain forward-looking statements involving risks and uncertainties. Our actual
results may differ materially from the results anticipated in these
forward-looking statements.

WE HAVE A HISTORY OF LOSSES AND MUST GENERATE GREATER REVENUE TO ACHIEVE
PROFITABILITY.

We commenced operations in 1997 and have been involved in two start-up
situations in Russia and the United States. Like most start up companies we have
incurred losses during our start up activities. Our current revenues are
insufficient to fund our medium and long-term business plans.

WE MIGHT NOT BE SUCCESSFUL IN ACQUIRING AND DEVELOPING NEW PROSPECTS AND OUR
EXPLORATION AND DEVELOPMENT PROPERTIES MAY NOT CONTAIN ANY SIGNIFICANT PROVED
RESERVES.

Our future success depends upon our ability to find, develop and acquire
additional economically recoverable oil and natural gas reserves. The successful
acquisition and development of oil and gas properties requires proper
forecasting of:

- an assessment of recoverable reserves,
- future oil and gas prices and operating costs,
- potential environmental and other liabilities, and
- productivity of new wells drilled.

These assessments are inexact. As a result, we might not recover the purchase
price of a property from the sale of production from the property, or might not
recognize an acceptable return from properties we acquire. Our estimates of
exploration, development and production costs can be affected by such factors
as:

- permitting regulations and requirements,
- weather, environmental factors,
- unforeseen technical difficulties, and
- unusual or unexpected formations, pressures and work interruptions.

Exploration and development involves significant risks. Few wells which are
drilled are developed into commercially producing fields. Substantial
expenditures may be required to establish the existence of proved reserves, and
we cannot assure you that commercial quantities of oil and gas deposits will be
discovered sufficient to enable us to recover our exploration and development
costs or be sufficient to sustain our business.

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EXPANSION OF OUR OPERATIONS WILL REQUIRE SIGNIFICANT CAPITAL EXPENDITURES FOR
WHICH WE MAY BE UNABLE TO PROVIDE SUFFICIENT FINANCING. OUR NEED FOR ADDITIONAL
CAPITAL MAY HARM OUR FINANCIAL CONDITION.

We will be required to make substantial capital expenditures to develop our
existing reserves and to discover new oil and gas reserves. Historically, we
have relied, and continue to rely, on external sources of financing to meet our
capital requirements, to continue acquiring, exploring and developing oil and
gas properties and to otherwise implement our corporate development and
investment strategies. We have, in the past, relied upon equity capital as our
principal source of funding. In October 2001, we completed approximately $18
million in equity financing. We plan to obtain the future funding we will need
through debt and equity markets, but we cannot assure you that we will be able
to obtain additional funding when it is required. We also make offers to acquire
oil and gas properties in the ordinary course of our business. If these offers
are accepted, our capital needs may increase substantially. If we fail to obtain
the funding that we need when it is required, we may have to forego or delay
potentially valuable opportunities to acquire new oil and gas properties or
default on existing funding commitments to third parties and forfeit or dilute
our rights in existing oil and gas property interests. Our limited operating
history may make it difficult to obtain future financing.

YOU SHOULD NOT UNDULY RELY ON RESERVE INFORMATION BECAUSE RESERVE INFORMATION
REPRESENTS ESTIMATES.

Estimates of oil and natural gas reserves involve a great deal of uncertainty,
because they depend in large part upon the reliability of available geologic and
engineering data, which is inherently imprecise. Geologic and engineering data
are used to determine the probability that a reservoir of oil and natural gas
exists at a particular location, and whether oil and natural gas are recoverable
from a reservoir. Recoverability is ultimately subject to the accuracy of data
regarding, among other factors:

- geological characteristics of the reservoir structure,
- reservoir fluid properties,
- the size and boundaries of the drainage area, and
- reservoir pressure and the anticipated rate of pressure depletion.

The evaluation of these and other factors is based upon available seismic data,
computer modeling, well tests and information obtained from production of oil
and natural gas from adjacent or similar properties, but the probability of the
existence and recoverability of reserves is less than 100% and actual recoveries
of proved reserves usually differ from estimates.

Estimates of oil and natural gas reserves also require numerous assumptions
relating to operating conditions and economic factors, including, among others:

- the price at which recovered oil and natural gas can be sold,
- the costs associated with recovering oil and natural gas,
- the prevailing environment conditions associated with drilling and
production sites,
- the availability of enhanced recovery techniques,
- the ability to transport oil and natural gas to markets, and
- governmental and other regulatory factors, such as taxes and
environmental laws.

A change in any one or more of these factors could result in known quantities of
oil and natural gas previously estimated as proved reserves becoming
unrecoverable. For example, a decline in the market price of oil or natural gas
to an amount that is less than the cost of recovery of such oil and natural gas
in a particular location could make production thereof commercially
impracticable. The risk that a decline in price could have that effect is
magnified in the case of reserves requiring sophisticated or expensive
production enhancement technology and equipment, such as some types of heavy
oil. Each of these factors, by having an impact on the cost of recovery and the
rate of production, will also affect the present value of future net cash flows
from estimated reserves.

In addition, estimates of reserves and future net cash flows expected from them
prepared by different independent engineers, or by the same engineers at
different times, may vary substantially.

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INFORMATION IN THIS DOCUMENT REGARDING OUR FUTURE EXPLOITATION PROJECTS REFLECTS
OUR CURRENT INTENT AND IS SUBJECT TO CHANGE.

We describe our current exploration and development plans in this document.
Whether we ultimately implement our plans will depend on the following factors:

- availability and cost of capital,
- receipt of additional seismic data or the reprocessing of existing data,
- current and projected oil or gas prices,
- the costs and availability of drilling rigs and other equipment supplies
and personnel necessary to conduct these operations,
- success or failure of activities in similar areas,
- changes in the estimates of the costs to complete the projects,
- our ability to attract other industry partners to acquire a portion of
the working interest to reduce costs and exposure to risks, and
- decisions of our joint working interest owners.

We will continue to gather data about our projects and it is possible that
additional information will cause us to alter our schedule or determine that a
project should not be pursued at all. You should understand that our plans
regarding our projects might change.

OUR BUSINESS MAY BE HARMED IF WE ARE NOT ABLE TO RETAIN OUR LICENSES, LEASES AND
WORKING INTERESTS IN LICENSES AND LEASES.

Some of our properties are held in the form of licenses and leases and working
interests in licenses and leases. If we or the holder of the license or lease
fails to meet the specific requirements of each license or lease, the license or
lease may terminate or expire. We cannot assure you that any of the obligations
required to maintain each license or lease will be met. The termination or
expiration of our licenses or leases or our working interest relating to a
license or lease may harm business. Some of our property interests will
terminate unless we fulfill certain obligations under the terms of our
agreements related to such properties. If we are not able to satisfy these
conditions on a timely basis, we may lose our rights in these properties. The
termination of our interests in these properties may harm our business.

WE ARE NOT ABLE TO GUARANTEE THE SUCCESSFUL COMMERCIAL DEVELOPMENT OF OUR
LICENSED "GAS-TO-LIQUIDS" TECHNOLOGY.

To date, no commercial-scale gas-to-liquids ("GTL") plants have been constructed
using the proprietary GTL process we license from Syntroleum Corporation
("Syntroleum") and, therefore, the process has not been proven on a commercial
scale. Other commercial developers of GTL technology include Exxon Mobil, Shell
and Sasol, each of which has significant financial resources and may be able to
use its greater financial flexibility to commercialize their GTL technologies
and commence production of GTL products earlier than we and Syntroleum can,
thereby obtaining a potential competitive advantage. This advantage may prove to
be particularly important as GTL project developers compete to obtain the most
attractive stranded natural gas deposits to provide feedstock for their plants.

CRUDE OIL AND NATURAL GAS PRICES ARE VOLATILE.

Fluctuations in the prices of oil and natural gas will affect many aspects of
our business, including:

- our revenues, cash flows and earnings,
- our ability to attract capital to finance our operations,
- our cost of capital,
- the amount we are able to borrow, and
- the value of our oil and natural gas properties.

Both oil and natural gas prices are extremely volatile. Oil prices are
determined by international supply and demand. Political developments,
compliance or non-compliance with self-imposed quotas, or
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agreements between members of the Organization of Petroleum Exporting Countries
can affect world oil supply and prices. Any material decline in prices could
result in a reduction of our net production revenue and overall value. The
economics of producing from some wells could change as a result of lower prices.
As a result, we could elect not to produce from certain wells. Any material
decline in prices could also result in a reduction in our oil and natural gas
acquisition and development activities.

In addition, a material decline in oil and natural gas prices from historical
average prices could adversely effect our ability to borrow and to obtain
additional capital on attractive terms.

Volatile oil and gas prices make it difficult to estimate the value of producing
properties for acquisition and often cause disruption in the market for oil and
gas producing properties, as buyers and sellers have difficulty agreeing on such
value. Price volatility also makes it difficult to budget for and project the
return on acquisitions and development and exploration projects.

GOVERNMENT REGULATIONS IN FOREIGN COUNTRIES MAY LIMIT OUR ACTIVITIES AND HARM
OUR BUSINESS OPERATIONS.

In addition to our interest in our China project, we may enter into contractual
arrangements to acquire oil and gas properties in other foreign jurisdictions
with governments, governmental agencies or government-owned entities. The
foreign legal framework for these agreements, particularly in developing
countries, is often based on recent political and economic reforms and newly
enacted legislation, which may not be consistent with long-standing local
conventions and customs. As a result, there may be ambiguities, inconsistencies
and anomalies in the agreements or the legislation upon which they are based
which are atypical of more developed western legal systems and which may affect
the interpretation and enforcement of our rights and obligations and those of
our foreign partners. Local institutions and bureaucracies responsible for
administering foreign laws may lack a proper understanding of the laws or the
experience necessary to apply them in a modern business context. Foreign laws
may be applied in an inconsistent, arbitrary and unfair manner and legal
remedies may be uncertain, delayed or unavailable.

WE MAY NOT BE SUCCESSFUL IN NEGOTIATING ADDITIONAL PRODUCTION SHARING CONTRACTS
IN CHINA.

We hold our interest in our China project through a production sharing contract
with China National Petroleum Corporation ("CNPC"). We also have two memoranda
of understanding with CNPC's subsidiary, PetroChina Corporation ("PetroChina"),
indicating a mutual intention to negotiate additional production sharing
contracts. We cannot assure you, based on our existing memoranda of
understanding with PetroChina, that we will successfully negotiate additional
production sharing contracts. It is possible that disputes between us could
arise in the future, which must be resolved under foreign law. We cannot be sure
that we can enforce our legal rights in foreign countries or that an effective
legal remedy will be available to us in any dispute governed by foreign law.

COMPLYING WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT OUR PRODUCTION.

Our operations are governed by numerous laws and regulations at various levels
of government in the countries in which we operate. These laws and regulations
govern the operation and maintenance of our facilities, the discharge of
materials into the environment and other environmental protection issues. The
laws and regulations may, among other potential consequences:

- require that we acquire permits before commencing drilling,
- restrict the substances that can be released into the environment in
connection with drilling and production activities,
- limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas,
- require that reclamation measures be taken to prevent pollution from
former operations,
- require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells and remediating contaminated soil and
groundwater, and
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- require remedial measures be taken with respect to property designated
as a contaminated site, for which we are a responsible person.

Under these laws and regulations, we could be liable for personal injury,
clean-up costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain limited insurance
coverage for sudden and accidental environmental damages as well as
environmental damage that occurs over time. However, we do not believe that
insurance coverage for the full potential liability of environmental damages is
available at a reasonable cost. Accordingly, we could be liable, or could be
required to cease production on properties, if environmental damage occurs.

The costs of complying with environmental laws and regulations in the future may
harm our business. Furthermore, future changes in environmental laws and
regulations could occur that result in stricter standards and enforcement,
larger fines and liability, and increased capital expenditures and operating
costs, any of which could have a material adverse effect on our financial
condition or results of operations.

WE COMPETE FOR OIL AND GAS PROPERTIES WITH MANY OTHER EXPLORATION AND
DEVELOPMENT COMPANIES THROUGHOUT THE WORLD WHO HAVE ACCESS TO GREATER FINANCIAL,
TECHNICAL AND HUMAN RESOURCES.

We operate in a highly competitive environment in which we compete with other
exploration and development companies to acquire a limited number of prospective
oil and gas properties. Many of our competitors are much larger than we are and
have greater financial, technical and human resources than we do and, as a
result, enjoy a competitive advantage. They may be able to pay more for
productive oil and gas properties and exploratory prospects and to define,
evaluate, bid for and purchase a greater number of properties and prospects than
our financial, technical and human resources permit.

OUR SHARE OWNERSHIP IS HIGHLY CONCENTRATED AND, AS A RESULT, OUR PRINCIPAL
SHAREHOLDERS CONTROL OUR BUSINESS.

Our directors and executive officers, including Robert M. Friedland,
collectively own or have rights to acquire approximately 36% of our common stock
and control our Board of Directors and determine our policies, business and
affairs and the outcome of any corporate transaction or other matter, including
mergers, consolidations and the sale of all or substantially all of our assets.

In addition, the concentration of our ownership may have the effect of delaying,
deterring or preventing a change in control that otherwise could result in a
premium in the price of our common stock.

IF WE LOSE OUR KEY MANAGEMENT AND TECHNICAL PERSONNEL, OUR BUSINESS MAY SUFFER.

We rely upon a relatively small group of key management and technical personnel.
We do not maintain any key man insurance. We do not have employment agreements
with certain of our key management and technical personnel and we cannot assure
you that these individuals will remain with us in the future. An unexpected
partial or total loss of their services would harm our business.

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

CORPORATE OVERVIEW

We are an international energy company engaged in conventional oil exploration
and production, enhanced oil recovery projects and the development of
gas-to-liquids projects. We were incorporated pursuant to the laws of the Yukon
Territory, Canada, on February 21, 1995 under the name 888 China Holdings
Limited. We were largely inactive until early 1996. On June 3, 1996, we changed
our name to Black Sea Energy Ltd., and on June 24, 1999, we changed our name to
Ivanhoe Energy Inc.

Our authorized capital consists of an unlimited number of common shares without
par value and an unlimited number of preferred shares without par value.

8

Our principal executive offices are located at Suite 654 -- 999 Canada Place,
Vancouver, British Columbia, V6C 3E1, and our registered and records offices are
located at 300-204 Black Street, Whitehorse, Yukon, Y1A 2M9.

OVERVIEW OF THE BUSINESS

Ivanhoe Energy Inc. is a company focused on three major strategies: (1)
production of synthetic fuels from natural gas using gas-to-liquids ("GTL")
technology; (2) conventional exploration and production ("E&P"), primarily
natural gas in the United States; and (3) enhanced oil recovery ("EOR") and
natural gas projects, on a production-sharing basis, with national petroleum
companies.

Following our incorporation in February, 1995, we were largely inactive until
early 1996, when we commenced our business as an acquirer, explorer and
developer of oil and gas properties. Initially, we concentrated our efforts on
acquiring oil and gas properties in Russia. Our strategy was to seek out
existing oil and gas properties in Russia on which past drilling and field
development practices did not maximize reserve recoveries and to establish joint
ventures with local partners to rehabilitate existing wells to recover
additional production. We achieved great success with our development and
rehabilitation activities at our Kalchinskoye field joint venture project in
western Siberia. However a dispute with our joint venture partner which
commenced in May 1998, prevented us from proceeding with our operations in the
area. In August 2000 we settled our dispute and disposed of our Russian assets
for approximately $29 million, bringing to an end our activities in Russia.

In the third quarter of 1998, we began to implement a diversification program
aimed at expanding the geographical scope of our business beyond Russia. We
added three individuals to our Board of Directors who have international
experience in the oil and gas industry. David Martin, who is now our Chairman,
was formerly the President and Chief Executive Officer of Occidental Oil & Gas
Corporation. E. Leon Daniel, who is now our President and Chief Executive
Officer, and John Carver, who is now one of our directors, are also both former
executives of Occidental Oil & Gas Corporation. In August, 1998, we began
acquiring oil and gas exploration property interests in Peru (which we
relinquished in 2000) and California. In 1999, we acquired property interests in
China. In April, 2000 we acquired a limited volume license from Syntroleum, to
use its proprietary GTL technology to convert natural gas into synthetic fuels.
We subsequently upgraded our limited volume license to a master license without
volume limitations. In May, 2000, we began acquiring interests in oil and gas
exploration properties in Texas and in March 2001, we acquired interests in oil
and gas exploration properties in Kentucky.

In California, we have been accumulating working interests and royalty interests
in the San Joaquin Valley since 1998, primarily through an exploration agreement
with Aera Energy LLC ("Aera"), which entitled us to explore and identify oil and
gas prospects in the San Joaquin Valley using exploration, seismic and technical
data owned by Aera. See "Oil and Gas Properties -- California"

In June, 1999, we further expanded the geographical scope of our business into
China by acquiring Sunwing Energy Ltd. ("Sunwing"), an oil and gas company. As a
result of our acquisition of Sunwing, we acquired two production sharing
contracts with CNPC to develop and operate the Kongnan oilfield in Dagang,
located in Hebei Province and the Zhaozhou oilfield in Daqing, located in
Heilongjiang Province. See "Oil and Gas Properties -- China". In February 2001,
we entered into two memoranda of understanding with PetroChina Company Limited,
("PetroChina") a subsidiary of CNPC, which gives us the exclusive right to
negotiate petroleum contracts for the development of oil and gas reserves in
three blocks in the Sichuan Basin. The Sichuan Basin is a major oil and gas
producing region of China located approximately 930 miles southwest of Beijing.
We are undertaking feasibility studies on the three blocks. If the results are
positive, we will commence negotiating production sharing contracts.

In May, 2000, we entered into an agreement with Discovery Operating, Inc.
("Discovery") to earn working interests ranging from 40% to 96% (reducing to
between 32% and 77% after pay out) in approximately 10,000 gross acres of oil
and gas exploration property in the Spraberry Trend of the West Texas Permian
Basin in Midland County, Texas. During 2000 and 2001 we leased the mineral
rights in 48,250 gross acres in the Bossier gas sands in east Texas and in 2001
entered into a joint venture agreement with a
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subsidiary of Unocal Corp. ("Unocal") to explore and develop prospects in the
Bossier Trend. See "Oil and Gas Properties -- Texas ".

In 2001, the Company acquired a 50% working interest in an exploration project
in the Rome Trough in Kentucky. See "Oil and Gas Properties -- Kentucky".

The master license we acquired from Syntroleum allows us to use Syntroleum's
proprietary process to convert natural gas into synthetic oil, transportation
fuels and other synthetic petroleum products. We plan to use the technology in
areas with large natural gas deposits, which would otherwise be uneconomic to
develop. Our master license entitles us to use the Syntroleum proprietary
process in an unlimited number of gas-to-liquids projects throughout the world
(excluding North America, China and India).

We are actively pursuing development and production sharing contracts for GTL
plants in both Qatar and Egypt and have undertaken feasibility studies during
2001 in connection with these opportunities. We have also agreed in principle to
become a partner in Syntroleum's Sweetwater GTL project in Western Australia. To
date, we have invested $2 million. Subject to certain conditions, including
Syntroleum's obligation to arrange project financing, we may invest an
additional $19 million to become a 13% equity partner in the project. See
"Gas-to-Liquids Projects".

CORPORATE STRATEGY

Our goal is to create a diversified global energy company focused on GTL, E&P
and EOR. We believe we can successfully implement our strategy and position
ourselves to compete over the longer term in what we expect will be a rapidly
evolving energy industry.

Our business plan is multi-faceted and involves the pursuit of objectives with
short, medium and long term impacts on our business. Our short-term objective is
to focus on areas where production can be achieved quickly and efficiently to
create cash flow to fund our operations and allow us to pursue our medium and
long-term objectives. To date, we have established production in the Spraberry
Trend of West Texas and at South Midway Sunset in the San Joaquin Basin of
California. Sunwing has also established production at its Dagang project in
China as part of its completed pilot-test program.

The cornerstone of our medium term strategy is deep gas exploration in the San
Joaquin Basin of California and in the Bossier gas sands of east Texas. Since
1999 we have accumulated substantial acreage in the San Joaquin Basin. We are in
the process of interpreting an 80,000 acre three-dimensional seismic survey
along the west side of the San Joaquin Valley which we are using to identify
drilling targets. In August 2001, we spud our first deep gas exploration well in
the Northwest Lost Hills area of the San Joaquin Basin with our partner, Aera as
the operator. In November 2001 we spud our first well in the Cresslen Ranch
prospect in the Bossier gas sands of east Texas with our partner Unocal.

We continue to pursue our enhanced oil recovery initiatives in China and larger
natural gas project opportunities under our Sichuan memoranda of understanding
with PetroChina. We remain encouraged by the results achieved in our pilot
program at Dagang and intend to proceed with the development phase of the
project once our development plan is approved by Chinese government authorities.
Based on our decision to concentrate on larger projects in China, we decided to
dispose of our smaller Daqing project. See "Oil and Gas Properties -- China". We
also are seeking other opportunities in China and elsewhere to acquire interests
in fields with economic development potential.

Our long-term objective is to become a leader in the development and operation
of GTL projects. We foresee rapidly increasing future demand for clean energy as
environmental regulations become more stringent and the world's crude oil
becomes more sour and heavy. We believe that Syntroleum's proprietary GTL
technology holds significant potential for the economic production of synthetic
fuels and other specialty petroleum products from stranded natural gas deposits
throughout the world, which would otherwise be uneconomic to exploit. Although
there are several competing GTL technologies under development, we believe that
the Syntroleum technology offers several key advantages. Plant

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construction is less expensive and the plant is safer to operate because, unlike
competing technologies, it uses compressed air rather than oxygen.

With our master license to use Syntroleum's proprietary GTL technology, we are
currently pursuing opportunities in Qatar and Egypt to obtain rights to stranded
natural gas deposits to use as feedstock for gas-to-liquids projects. We believe
that synthetic fuels and specialty products produced using GTL processes will
eventually present an attractive, economic and environmentally superior
alternative to traditional fuels derived from crude oil.

GAS-TO-LIQUIDS PROJECTS

SYNTROLEUM LICENSE

We hold a non-exclusive master license entitling us to use Syntroleum's
proprietary GTL process in an unlimited number of projects in all areas of the
world (other than North America, China and India) with unlimited production
volume restrictions.

SYNTROLEUM PROCESS

Syntroleum's proprietary GTL process is designed to catalytically convert
natural gas into synthetic liquid hydrocarbons. This process (the "Syntroleum
Process") is designed to substantially reduce the capital and operating cost and
the minimum economic size of a GTL plant.

Syntroleum developed its GTL technology based on a process developed in Germany
in the 1920s for the gasification of coal into oil, called the Fischer-Tropsch
reaction. Syntroleum has applied its principles to the conversion of natural gas
to synthetic liquid hydrocarbons. Syntroleum believes that it holds a
competitive advantage over other GTL technologies because the Syntroleum Process
compresses air directly from the atmosphere when converting natural gas into
synthetic hydrocarbons. The GTL processes developed by Syntroleum's competitors
use either steam reforming or a partial combination of steam reforming and
partial oxidation with pure oxygen. A steam reformer and an air separation plant
necessary for oxidation are bulky, expensive and increase operating costs. The
Syntroleum Process allows for the operation of GTL plants without an air
separation plant or steam reformer, thereby reducing capital costs, operating
costs, the size and complexity of a GTL plant and operating volatility.

From our perspective, the greatest opportunity for the use of the Syntroleum
Process lies in the extraction of stranded natural gas. Stranded natural gas
exists in known reservoirs, which cannot be marketed on an economic basis.
Operators consider natural gas to be stranded based on the relative size of the
fields, the location of the natural gas relative to its market and the cost to
transport the natural gas to markets.

GTL PROSPECTS

During 2001 we undertook detailed project feasibility studies for the
construction, operation and cost of GTL plants in both Qatar and Egypt. The
study for Qatar examined the potential for development of offshore natural gas,
conveyance of natural gas to shore and its subsequent dehydration, gas liquids
extraction through a natural gas liquids plant with production capacity of up to
185,000 barrels per day, product storage and offloading facilities. The study
also examined four alternative plant designs. The first was a maximum efficiency
case in which production was maximized. A second case considered the same GTL
production efficiency with supplemental power and water being manufactured from
the waste heat. A third case addressed maximum efficiency with maximized water
production. The fourth case focused on maximized power and water manufacture for
export. All cases were required to address the various needs of the host
government and will be further evaluated during currently ongoing commercial
discussions with Qatari authorities.

While many of the issues addressed in the feasibility studies we have undertaken
for Qatar are also applicable to Egypt, the feasibility studies we have
undertaken for Egypt contemplate the natural gas feedstock being purchased,
rather than developed, and production capacity in the order of 90,000
11

barrels per day. The results of the feasibility studies for Egypt will be
utilized during the course of commercial discussions with Egyptian authorities,
which we have yet to formally initiate.

We have conducted marketing and transportation feasibility studies for both
Europe and Asia Pacific regions in which we identified potential markets and
estimated premiums for GTL diesel and naphtha. We have also recently undertaken
a commercialization study in Japan in conjunction with Inpex Corporation and
Mitsui & Co. Ltd., of Japan, and Qatar Petroleum to study the role that Japanese
companies can play as purchasers of GTL and natural gas liquids products and as
suppliers of equipment, materials, services and project financing. We plan to
use the results of these studies as the basis for evaluating the commerciality
of our GTL opportunities.

SWEETWATER GTL PROJECT

In 2000, we signed a letter of intent to invest $21 million to participate as a
13% partner in Syntroleum's Sweetwater GTL project in Western Australia. The
project is a 10,000 barrels per day plant that will produce specialty products
such as lubricants, industrial fluids and liquid normal paraffins, as well as
synthetic fuels. We made a $2 million advance for front-end engineering and
other costs. The balance of the investment is subject to a number of conditions,
including Syntroleum's obligation to arrange project financing.

Syntroleum has made progress in developing the project but continues to seek
financing. We have since identified two larger GTL project opportunities in
Qatar and Egypt, which may affect our continuing participation in Sweetwater but
no decision has been reached at this time.

OIL AND GAS PROPERTIES

Our primary oil and gas properties are located in the San Joaquin Valley area of
California. We also hold interests in exploration and development properties in
Texas and Kentucky in the United States and in Hebei Province in China. Set
forth below is a description of our material oil and gas properties.

CALIFORNIA

Over the past four years, we have acquired interests in a number of properties
in and around the San Joaquin Basin area of Southern California. To date, only
our South Midway Sunset project contains proved reserves and has wells on
production. We cannot assure you that any of our other prospects in California
will result in the development of commercially viable production.

AERA EXPLORATION AGREEMENT

In 1998, we acquired rights to an exploration agreement with Aera covering an
area of more than 250,000 acres in the San Joaquin Valley. The Aera exploration
agreement gave us access to all of Aera's exploration, seismic and technical
data in the region for the purpose of identifying drillable exploration
prospects within the exclusive area. We have a right to a working interest
ownership in the drillable prospects in which Aera elects to participate and
Area has the right to act as the operator for any drillable prospects in which
it elects to participate.

Except for those prospect areas of mutual interest ("AMIs") previously
designated by us and accepted by Aera, our exclusive rights to explore Aera's
properties expired in September 2001. We will continue to hold exploration
rights to the lands within previously designated and accepted prospect AMIs
until an exploration well is drilled in that prospect and the prospect has been
evaluated. Although the Aera exploration agreement provides that Aera's working
interest in these prospects will range from a minimum of 25% to a maximum of
87.5%, we have negotiated different working interest allocations with Aera on a
prospect basis. Aera is obliged to assign to us any working interest in the
prospect that it does not retain. Once we identify a drillable prospect and
agree upon working interests with Aera, we have an indefinite time to carry out
exploration drilling if Aera elects to participate in the prospect. If Aera
elects to participate but not to drill the designated prospect, or elects not to
participate, we have

12

an additional two years to drill the prospect on our own or with other parties.
This two-year period will be extended as long as we continue to drill or have
established production.

The properties covered by the Aera exploration agreement are located in Kern,
Kings, Tulare, Fresno, San Benito, Monterey and San Luis Obispo Counties. Using
the extensive proprietary seismic and technical databases owned by Aera and
supplemented by us, we have identified over forty prospects within 18 prospect
AMIs covering approximately 72,800 acres. Of the 18 prospect AMIs we have
submitted, Area has elected to take a working interest in 12 areas: Diamond,
Northwest Lost Hills, Amethyst, Belgian Anticline, Emerald, Sapphire, Ruby,
North Basil, Cinnamon, Sage, Nutmeg and Rosemary, in which we have working
interests ranging from 12.5% to 50%. Aera has yet to make an election on two
submitted prospect AMIs: Jacaranda and Coles Levee. We have a 100% working
interest in the three prospect AMIs in which Aera elected not to participate.
One of these prospects is South Midway Sunset on which we have, to date, drilled
29 successful wells. The second prospect AMI is Citrus and the third is North
Yowlumne where we are planning to obtain 3-D seismic. Neither we nor Aera plan
to participate in the Kern River AMI and we have farmed out this AMI and
retained an overriding royalty interest. We have relinquished our interests in
all other Aera exploration agreement properties.

Set forth below is a description of our material exploration and development
activities under the Aera exploration agreement.

- - Northwest Lost Hills

Our first deep-gas exploration well in the San Joaquin Valley, known as the
Aera/Ivanhoe Northwest Lost Hills #1-22 well located in Kern county, was spud in
August 2001. The well was drilled to a depth of 18,400 feet and encountered the
top of the targeted Temblor formation. Prior to the setting of casing, we
determined, based on geological information, that the bottom hole could be
placed in a more structurally favorable location so we sidetracked the well and
we are currently setting casing down to approximately 17,000 feet. The target
depth of the well is 20,000 feet. The well lies five miles northwest of, and on
a trend with, the Bellevue No. 1 blowout well, drilled by Berkley Petroleum
Corp. (later acquired by Anadarko Petroleum Corporation), which was a Temblor
gas discovery. In the 9,600 gross acres owned and under option encompassing the
Northwest Lost Hills prospect, we hold on average a 39% working interest. We
have a 42% working interest in the Aera/Ivanhoe Northwest Lost Hills #22-1 well.

- - Amethyst

We have identified a prospect in the northern part of the South Belridge area
where we currently hold a 12.5% working interest. We originally expected to
commence drilling the prospect in late 2001, but delayed drilling in order to
shoot additional modern 2-D seismic, which we are currently interpreting. We now
expect to drill during the second quarter of 2002.

- - Diamond

We have completed a 3-D seismic survey covering the majority of this prospect
and we are continuing to interpret the results. We currently have a minimum
working interest of 12.5% in this prospect.

- - Belgian Anticline

We identified a drillable prospect on the western flank of the Belgian Anticline
area and spudded a well late in 2000. We encountered three potential
hydrocarbon-bearing zones but two of the zones we tested were not capable of
commercial production. Our testing of the third zone was inconclusive due to
technical difficulties. Aera is currently processing some additional geophysical
information and we are awaiting Aera's recommendation. We hold a 40% working
interest in the prospect and Aera holds the balance.

13

- - South Midway Sunset

By the end of 2001, we had drilled 31 wells in the South Midway field, 29 of
which are producing oil at commercial rates. We are currently producing
approximately 400 net barrels of oil per day. In the fourth quarter of 2001 we
completed a pilot cyclic steam project, which was successful in more than
doubling production rates in the five wells that we treated. We are now planning
a full scale cyclic steam project to commence in 2002. South Midway provides us
with immediate cash flow from a low risk, low cost development project with
existing infrastructure. We own a 100% working interest and a 93% net revenue
interest in the project. Aera elected not to participate in this project but
receives royalties pursuant to the Aera exploration agreement.

- - Citrus

We have deferred drilling a well in this prospect until we can find a partner to
participate in the funding of the drilling and until gas and oil prices
stabilize. We own a 100% working interest in the prospect.

- - Emerald, Sapphire and Ruby

We have a 12.5% working interest in each of these three prospects. We are
planning to drill an exploration well in the Emerald prospect in the fourth
quarter of 2002. Our plans for exploration activities in Sapphire and Ruby will
depend on the results of the Emerald well.

- - North Basil, Cinnamon, Sage, Nutmeg and Rosemary

We have a 50% working interest in each of these five prospects. Depending on the
results of the Aera/Ivanhoe Northwest Lost Hills #1-22 well, we may drill an
exploration well on one of these prospects in 2002.

OTHER SOUTHERN CALIFORNIA

NORTH SOUTH FORTY

In September 15, 1999, we entered into an agreement with Prime Natural
Resources, LLC ("Prime") to jointly conduct a 3-D seismic survey in the southern
San Joaquin Valley basin in order to identify new prospects over an area of
approximately 80,000 acres. We subsequently entered into an exploration
agreement with Prime and Aera in which we agreed to pool certain of our acreage
positions in the basin to share the costs of carrying out the 3-D seismic
program and to broaden our respective interests in the area. The pooled acreage
under the agreement is divided into four areas called North South Forty Areas A,
B, C and D. Each party retains an equal interest in the data generated from the
3-D seismic program, except Aera retains an interest in only the data generated
in areas A and B. All costs of carrying out the program will be borne equally by
Prime and us. Our working interests range from 17.5% to 50% in these four areas.
The 3-D seismic program is intended to identify prospects for exploration
drilling. Once prospects have been identified, each party may elect to
participate in a drilling program. We started evaluating the results of the
program in the second half of 2001 and our evaluation remains ongoing.

MAGIC MOUNTAIN / OROFINO

Our NL&F Magic Mountain #1 well in Los Angeles county and our OroFino well in
San Luis Obispo county were drilled in 2001, were unsuccessful at finding
commercial hydrocarbons and abandoned. Neither prospect was in the San Joaquin
Valley or part of the Aera exploration agreement.

TEXAS

SPRABERRY

In April 2000, we entered into an agreement with Discovery relating to
approximately 10,000 gross acres of oil and gas exploration property in the
Spraberry Trend of the West Texas Permian Basin in Midland

14

County. Under the terms of our agreement, we hold, until payout of our costs, a
96.15% working interest (77% after payout) in the first four wells and a 62.5%
working interest (50% after payout) in the remaining wells on approximately
7,900 gross acres. We hold a 40% working interest (32% after payout) on
approximately 1,700 gross acres covered by a farm-out agreement. Discovery is
the operator.

As of the end of 2001 we drilled 30 wells in the Spraberry field, which are
currently producing approximately 300 net barrels of oil equivalent per day. All
30 wells have been completed in one or more of the Wolfcamp zones. However, 5
wells still are awaiting their Spraberry zone completions. We plan to start
these completions in early 2002 and finish them by the end of 2002. During 2002,
we may also drill an additional six to eight wells in the area known as Apache
Flats where we have a 40% working interest before payout. To date we have
drilled three wells in this area and each is producing approximately 40 net
barrels of oil equivalent per day.

Further field development has been curtailed pending results from our planned
activities and stabilizing of commodity prices.

BOSSIER

We have leased mineral rights in 58,000 gross (44,000 net) acres in the Bossier
Trend in east Texas under a joint venture with Unocal. Eight prospects have been
identified within this acreage. Unocal is the operator of the joint venture and
will fund the drilling costs for the first several exploration wells to offset
the $10 million in leasehold, seismic and processing costs we have already
incurred. After our respective investments in the joint venture have been
equalized we will share exploration, development and infrastructure costs
equally.

Two wells were spud in the Cresslen Ranch prospect. The 1-Trinity Materials well
was drilled to a depth of 12,240 feet and encountered approximately 120 net feet
of Bossier sand, which indicates the potential for natural gas production. The
2-Trinity Materials well was drilled to a depth of 11,583 feet and also
encountered approximately 220 feet of net Bossier sand. We have commenced
fracturing operations and expect to test the well shortly. We plan to drill
several additional wells in the Bossier trend by the end of 2002. Our working
interest in the Bossier sands is subject to leasehold burdens and a 9.375% net
profit interest.

KENTUCKY

In March of 2001 we entered into a joint venture with Hay Exploration, Inc. to
explore for natural gas in the Rome Trough of eastern Kentucky. We each hold a
50% interest. We have identified three prospect areas covering 15,000 net acres
and during 2001 we drilled an exploration well in each prospect area. One well
was suspended pending further evaluation. Preliminary analysis of the drilling
logs for the remaining two wells indicates several potential gas pay zones.
Inclement weather and unavailability of completion rigs has delayed the testing
of these two wells. The wells were perforated early in 2002 and we plan to
fracture stimulate both wells in the near future.

CHINA

We hold interests in China through our wholly owned subsidiary Sunwing.

DAGANG PROJECT

Our principal asset in China is a 20-year production sharing contract with CNPC,
covering an area of 22,400 gross acres divided into six blocks in the Kongnan
oilfield in Dagang, Hebei Province, China (the "Dagang Project"). Under the
contract we operate the project and fund 100% of the development costs to earn
82% of the net revenue from oil production until cost recovery, at which time
our entitlement reduces to 49%.

We have a marketing arrangement with CNPC whereby we have the option of either
exporting our share of oil production or selling it to them. We are currently
selling our crude oil to CNPC at a three month
15

rolling average price of Cinta crude oil as published by Platts. The average
price of Cinta crude oil over the last three years is approximately $2.00 per
barrel less than the West Texas Intermediate ("WTI") price. All sales are
settled in United States dollars.

We are obliged to pay value added tax of 5% on oil production from the Dagang
Project. We pay no royalty until annual gross production of crude oil from a
particular block within the Dagang Project exceeds 500,000 tonnes per annum.
Royalties then become payable at a rate of 2% and increase incrementally as the
rate of production increases to a maximum of 12.5% once annual gross production
on a block exceeds four million tonnes. We do not expect that any of the blocks
will produce more than 500,000 tonnes per annum and as such no royalty payments
are anticipated. Our entire interest in the Dagang Project will revert to CNPC
at the end of the 20-year production period or if we abandon the project
earlier.

In 1999 we farmed out a 20% working interest in the Dagang project to Nippon Oil
Exploration Limited ("Nippon") for which Nippon agreed to fund $6 million of
pilot testing expenditures. At the end of the pilot phase, Nippon elected to
relinquish its 20% working interest back to us.

During 2001, we completed the pilot testing phase and submitted an overall
development plan to Chinese regulatory authorities for approval. We expect to
receive this approval during the first half of 2002. The development phase of
the Dagang project will commence once all necessary approvals and financing have
been received. The development phase will cost approximately $185 million over a
three-year period and will involve drilling 115 new wells and reworking
approximately 29 of the 82 existing wells.

DAQING PROJECT

Until January 2002 we were party to another production sharing contract with
CNPC which covers an area of 8,100 gross acres in the Zhaozhou oilfield in
Daqing, Heilongjiang Province, China (the "Daqing Project"). The Daqing Project,
which is relatively small, was initially undertaken by us on the expectation
that we would be able to acquire rights to additional land blocks. Our
negotiations were unsuccessful to acquire the additional blocks necessary to
provide critical mass. We decided to divest of our interest in the Daqing
Project and in January 2002, we sold our interest in the Daqing Project for $2.4
million and a right to an overriding royalty on future production.

SICHUAN BASIN

In February 2001, we signed two memoranda of understanding with PetroChina.
These memoranda give us the exclusive right to negotiate petroleum contracts for
three land blocks in Sichuan province. We have agreed with PetroChina to carry
out joint feasibility studies on the Zitongxi, Zitongdong and Yudong blocks.
These blocks, located in the Sichuan Basin, approximately 930 miles southwest of
Beijing cover an area of approximately 2.2 million acres. If the results of the
joint feasibility studies are positive, we will proceed to negotiate production
sharing contracts, and seek Chinese regulatory approval. PetroChina has drilled
39 wells on the three blocks. Twenty-six of these wells have been classified as
producing gas wells. PetroChina has production tested 8 of the estimated 38
hydrocarbon bearing structures located on the three blocks. We are still in the
process of assessing the resources and formulating a potential development plan.

COMPETITION

The oil and gas industry is highly competitive. Our position in the oil and gas
industry, which includes the search for, and development of, new sources of
supply, is particularly competitive. The oil and gas industry also competes with
other industries in supplying energy, fuel and other needs of consumers. See
"Risk Factors."

16

ENVIRONMENTAL REGULATIONS

Both our oil and gas and GTL operations are subject to various levels of
government laws and regulations relating to the protection of the environment in
the countries in which they operate. We believe that our operations comply in
all material respects with applicable environmental laws.

In the United States, environmental laws and regulations, implemented
principally by the Environmental Protection Agency, Department of Transportation
and the Department of the Interior and comparable state agencies, govern the
management of hazardous waste, the discharge of pollutants into the air and into
surface and underground waters and the construction of new discharge sources,
the manufacture, sale and disposal of chemical substances, and surface and
underground mining. These laws and regulations generally provide for civil and
criminal penalties and fines, as well as injunctive and remedial relief.

In China, environmental regulation does not exist on a national level.
Individual projects are monitored by the state and the standard of environmental
regulation depends on each case.

GOVERNMENT REGULATIONS

Our business is subject to certain United States and Chinese federal, state and
local laws and regulations relating to the exploration for, and development,
production and marketing of, crude oil and natural gas, as well as environmental
and safety matters. In addition, the Chinese government regulates various
aspects of foreign company operations in China. Such laws and regulations have
generally become more stringent in recent years in the United States, often
imposing greater liability on a larger number of potentially responsible
parties. It is not unreasonable to expect that the same trend will be
encountered in China. Because the requirements imposed by such laws and
regulations are frequently changed, we are not able to predict the ultimate cost
of compliance.

EMPLOYEES

At March 1, 2002, we had 69 employees. None of our employees are unionized.

RESERVES, PRODUCTION AND RELATED INFORMATION

See the Supplementary Disclosures About Oil and Gas Production Activities
included under Item 8 in this Annual Report for information with respect to our
oil and gas producing activities. We have not filed with or included in reports
to any other United States federal authority or agency, any estimates of total
proved crude oil or natural gas reserves since the beginning of the last fiscal
year.

The following tables set forth, for each of the last three fiscal years, our
average sales prices and average production costs per unit of production.
Average sales prices are after royalties in the United States, China and Russia.
In China for 1999 and 2000, proceeds from the sale of oil produced were credited
to our China cost pool due to the stage of development of our projects in China.
In 2000, the average sales price realized on China production was $28.26 (1999
- -- $21.27). Average production costs include lifting costs and production taxes,
but exclude allocated head office engineering support costs, depreciation,
depletion and amortization, royalties, income taxes, interest and selling
administrative and other expenses.

17

The following tables set forth the number of productive wells (both producing
wells and wells capable of production) in which we held a working interest at
December 31, 2001 and 2000:

- ---------------

(1) Gross wells are the total number of wells in which an interest is owned.

(2) Net wells are the sum of fractional interests owned in gross wells.

The following table sets forth, for each of the last three fiscal years, our
participation in the completed drilling of net crude oil and natural gas wells:

EXPLORATORY

DEVELOPMENT

The following tables set forth our holdings of developed and undeveloped oil and
gas acreage at March 1, 2002:

- ---------------

18

(1) Gross acres include the interests of others.

(2) Net acres exclude the interests of others.

(3) The number of developed acres disclosed in respect of our China projects
relates only to those portions of the relevant fields covered by our pilot
testing operations and does not include the remaining portions of the
fields previously developed by CNPC.

The following table sets out estimates of our share of proved reserves in
respect of our United States and China operations and calculations of cash
flows, before tax and after tax, undiscounted and discounted at 10% and 15%,
based on costs and prices as at December 31, 2001. Estimates for our China
operations were prepared by independent petroleum consultants Gilbert Laustsen
Jung Associates Ltd.. Independent petroleum consultants Allan Spivack
Engineering and Joe C. Neal & Associates prepared estimates for our United
States operations.

- ---------------

(1) "Proved Reserves" are the estimated quantities of crude oil which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic
conditions. Our share of the reserves is shown before royalties. Our share
of the reserves net of royalties is disclosed in the "Supplementary
Disclosures about Oil and Gas Production Activities", which follow the
notes to our financial statements set forth in Item 8 of this Annual
Report.

(2) In late January 2002 we disposed of our interest in our Daqing project. For
purposes of this schedule the reserves for Daqing of 3,449 MBbl represent
the reserve volumes reported by Gilbert Lausten Jung Associates Ltd. as at
December 31, 2000 less 2001 production. The undiscounted value attributed
to the Daqing reserves of $5,185,000 before and after tax ($3,897,000
before and after tax discounted at 10%), represents the value of
consideration received on disposal.

ITEM 3. LEGAL PROCEEDINGS

We are not currently a party to any material legal proceedings.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

MARKET INFORMATION

Our common shares are traded on the NASDAQ National Market and The Toronto Stock
Exchange.

The high and low sale prices of our common shares as reported on the NASDAQ
National Market and the Toronto Stock Exchange for each quarter during the past
two years are as follows:

19

NASDAQ NATIONAL MARKET (IVAN)

- ---------------

(1) Our common shares did not commence trading on the NASDAQ National Market
until August 28, 2000.

THE TORONTO STOCK EXCHANGE (IE)
(CDN.$)

On March 1, 2002, the closing prices for our common shares were $2.00 on the
NASDAQ National Market and Cdn. $3.10 on The Toronto Stock Exchange.

HOLDERS OF COMMON SHARES

As at March 1, 2002, a total of 139,517,708 of our common shares were issued and
outstanding and held by 114 holders of record.

DIVIDENDS

We have not paid any dividends on our outstanding common shares since we were
incorporated and we do not anticipate that we will do so in the foreseeable
future. The declaration of dividends on our common shares is, subject to certain
statutory restrictions described below, within the discretion of our Board of
Directors based on their assessment of, among other factors, our earnings or
lack thereof, our capital and operating expenditure requirements and our overall
financial condition. Under the Yukon Business Corporations Act, our Board of
Directors has no discretion to declare or pay a dividend on our common shares if
they have reasonable grounds for believing that we are, or would after payment
of the dividend be, unable to pay our liabilities as they become due or that the
realizable value of our assets would, as a result of the dividend, be less than
the aggregate sum of our liabilities and the stated capital of our common
shares.

EXCHANGE CONTROLS AND TAXATION

There is no law or governmental decree or regulation in Canada that restricts
the export or import of capital, or affects the remittance of dividends,
interest or other payments to a non-resident holder of our common shares, other
than withholding tax requirements.

There is no limitation imposed by the laws of Canada, the laws of the Yukon, or
our constating documents on the right of a non-resident to hold or vote our
common shares, other than as provided in the Investment Canada Act (Canada) (the
"Investment Act"), which generally prohibits a reviewable investment by an
entity that is not a "Canadian", as defined, unless after review, the minister
responsible for the Investment Act is satisfied that the investment is likely to
be of net benefit to Canada. An investment in our common shares by a
non-Canadian who is not a "WTO investor" (which includes governments of, or
individuals who are nationals of, member states of the World Trade Organization
and corporations and other entities which are controlled by them), at a time
when we were not already controlled by a WTO investor, would be reviewable under
the Investment Act under two circumstances. First, if it was an investment to
acquire control (within the meaning of the Investment Act) and the value

20

of our assets, as determined under Investment Act regulations, was
Cdn.$5,000,000 or more. Second, the investment would also be reviewable if an
order for review was made by the federal cabinet of the Canadian government on
the grounds that the investment related to Canada's cultural heritage or
national identity (as prescribed under the Investment Act), regardless of asset
value. An investment in our common shares by a WTO investor, or by a
non-Canadian at a time when we were already controlled by a WTO investor, would
be reviewable under the Investment Act if it was an investment to acquire
control and the value of our assets, as determined under Investment Act
regulations, was not less than a specified amount, which for 2002 is Cdn.$218
million. The Investment Act provides detailed rules to determine if there has
been an acquisition of control. For example, a non-Canadian would acquire
control of us for the purposes of the Investment Act if the non-Canadian
acquired a majority of our outstanding common shares. The acquisition of less
than a majority, but one-third or more, of our common shares would be presumed
to be an acquisition of control of us unless it could be established that, on
the acquisition, we were not controlled in fact by the acquirer. An acquisition
of control for the purposes of the Investment Act could also occur as a result
of the acquisition by a non-Canadian of all or substantially all of our assets.

Amounts that we may, in the future, pay or credit, or be deemed to have paid or
credited, to you as dividends in respect of the common shares you hold at a time
when you are not a resident of Canada within the meaning of the Income Tax Act
(Canada) will generally be subject to Canadian non-resident withholding tax of
25% of the amount paid or credited, which may be reduced under the Canada-United
States Income Tax Convention (1980) (the "Convention"). Currently, under the
Convention, the rate of Canadian non-resident withholding tax on the gross
amount of dividends paid or credited to a U.S. resident is generally 15%.
However, if the beneficial owner of such dividends is a U.S. resident
corporation which owns 10% or more of our voting stock, the withholding rate is
reduced to 5%. In the case of certain tax exempt entities which are residents of
the United States for the purpose of the Convention, the withholding tax on
dividends may be reduced to 0%.

SALES OF UNREGISTERED SECURITIES

During the year ended December 31, 2001, we issued securities which were not
registered under the Securities Act of 1933 (the "Act") as follows:

- in May 2001, we issued 800,000 common shares to two of our existing
shareholders in exchange for all of the issued and outstanding shares of
Digital Petrophysics Resources, Inc., a company holding overriding
royalty interests in certain of our California exploration properties,
in a transaction exempt from registration under Section 4(2) of the Act;
and

- in October 2001, we issued 10,885,000 special warrants at a price of
$1.60 per special warrant to a number of Canadian individual and
institutional investors in a transaction exempt from registration under
Rule 903 of the Act and 375,000 special warrants at a price of $1.60 per
special warrant to two accredited investors in a transaction exempt from
registration under Rule 506 of the Act. Each special warrant was
exercisable to acquire, for no additional consideration, one common
share following the issuance of a receipt for a prospectus by applicable
Canadian provincial securities regulatory authorities, which occurred in
November 2001.

ITEM 6. SELECTED FINANCIAL DATA

The selected financial data set forth below are derived from the accompanying
financial statements, which form part of this Annual Report. The financial
statements have been prepared in accordance with generally accepted accounting
principles ("GAAP") applicable in Canada, which is not materially different from
GAAP in the United States, except in 2001 for which an additional impairment
provision for the carrying value of our China properties of $10 million and the
need to write-off development costs of $5.1 million in connection with our GTL
prospects are required under United States GAAP. For a United States GAAP
reconciliation, see Note 15 to our financial statements. See also Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operation".
21

The following table shows selected financial information for the periods
indicated:

- ---------------

(1) Includes asset write down of $14.0 million. For United States GAAP purposes
an additional asset write down of $15.1 million is required. See Note 15 to
our financial statements under Item 8 in this Annual Report.

(2) Includes asset write down of $2.5 million. See Note 8 to our financial
statements under Item 8 in this Annual Report.

(3) Includes asset write down $70.2 million. See Note 9 to our financial
statements under Item 8 in our 2000 Annual Report

RECONCILIATION TO GAAP IN UNITED STATES

Our financial statements have been prepared in accordance with GAAP applicable
in Canada, which differ in certain respects from those principles that we would
have followed had our financial statements been prepared in accordance with GAAP
in the United States. The only material differences between Canadian and United
States GAAP which affect our financial statements is that under United States
GAAP an additional impairment provision of $10 million and a write-off of $5.1
million in connection with development costs for our GTL prospects are required
in 2001. Determination of earnings per share in 1998, 1999 and 2000 is
calculated excluding shares held in escrow.

Had we followed U.S. GAAP, certain selected financial information reported above
would have been reported as follows. Potential exercise of the stock options and
warrants disclosed in Note 5 to the financial statements and potential
conversion of the debt, Note 4, do not have a material dilutive effect on the
earnings per share.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

CRITICAL ACCOUNTING PRINCIPLES AND ESTIMATES

Our accounting principles are described in Note 2 to Notes to the Consolidated
Financial Statements in Item 8. We prepare our Consolidated Financial Statements
in conformity with GAAP in Canada, which conform in all material respects to
United States GAAP except for those items disclosed in Note 2 to Notes to the
Consolidated Financial Statements. For United States readers we have detailed
the differences and have also provided a reconciliation of the differences
between United States and Canadian GAAP in Note 15 to Notes to the Consolidated
Financial Statements.

22

The preparation of our financial statements requires us to make estimates and
judgements that affect our reported amounts of assets, liabilities, revenue and
expenses. On an ongoing basis we evaluate our estimates, including those related
to asset impairment, revenue recognition, allowance for doubtful accounts and
contingencies and litigation. These estimates are based on information that is
currently available to us and on various other assumptions that we believe to be
reasonable under the circumstances. Actual results could vary from those
estimates under different assumptions and conditions.

We have identified the following critical accounting policies that affect the
more significant judgements and estimates used in preparation of our
consolidated financial statements.

Full Cost Accounting -- We follow the full cost method of accounting for our oil
and gas operations (as more fully described in Note 2 to the Consolidated
Financial Statements), as compared to the other generally accepted method,
successful efforts. Under the full cost method, costs associated with drilling
successful and unsuccessful wells are capitalized on a country-by-country basis.
As a consequence we may be more exposed to potential impairments if the book
value of capitalized costs exceeds their future expected cash flows. This may
occur if recoverable reserve estimates decrease, commodity prices decline or
future estimates for capital, operating and income taxes increase, to levels
that would significantly affect anticipated future cash flows.

Oil and Gas Reserves -- The process of estimating quantities of proved reserves
is inherently uncertain and the reserve estimates included in this document are
only estimates (see "Risk Factors"). You should not assume that the present
value of our future cash flows is the current market value of our estimated
proved oil and gas reserves. In accordance with GAAP we base the estimated
future net cash flows from proved reserves on prices and costs on the date of
estimate. Actual future prices and costs may be materially higher or lower than
the prices and costs at the date of estimate.

Depletion -- Our rate of recording depletion is dependent upon our estimate of
proved reserves. If the estimates of proved reserves decline, the rate at which
we record our depletion expense increases, reducing net income. Such a decline
in proved reserves may occur from lower product prices, which may make it
non-economic to drill for and produce higher cost fields.

YEAR ENDED DECEMBER 31, 2001

OVERVIEW

Our 2001 plan was to advance our short, medium and long-term objectives towards
our overall goal of creating a diversified global energy company focused on
three growth strategies: conventional E&P, EOR projects on a production-sharing
basis with national petroleum companies, and production of cleaner burning fuels
from natural gas using proven GTL technology.

Our short-term objective to secure cash flow was advanced through our activities
at our South Midway Sunset in California and Spraberry in west Texas as well as
the submission of our development plan in our EOR project at Dagang in China.
Our 2001 U.S. production increased almost 8 fold over 2000 to 232,600 Boe. Net
revenues from our U.S. projects increased to $5.1 million from $851,000 the
previous year. Our 2001 China pilot production increased 61% to 165,600 barrels
of oil with net revenue increasing $1.1 million to $4 million. Our operating
results however, suffered from the decline in oil and gas prices in the second
half of 2001. In the U.S. these declines necessitated a provision for impairment
of capitalized costs of $14 million and reduced our net revenue to $1.1 million
in the fourth quarter compared to $1.5 million in the previous quarter. In China
the fourth quarter decline in net revenue was less dramatic due to the impact of
three month averaging of our oil prices. However, on application of U.S. GAAP at
year-end an impairment provision of $10 million on the carrying value of our
China properties was necessary

Our medium-term objective to explore for deep gas in the San Joaquin Basin in
California and the Bossier gas sands in east Texas was advanced with the spud of
our Northwest Lost Hills 1-22 well in California in August, and the commencement
of drilling of our initial 2 wells at Bossier. In China we

23

identified an opportunity to participate in a major natural gas opportunity in
the Sichuan Basin and secured the exclusive right to negotiate
production-sharing contracts with PetroChina in 3 blocks.

We continue to advance our long-term strategy to become a leader in the
development of GTL projects through negotiations, currently underway, in Qatar
and Egypt to secure the rights to exploit stranded natural gas reserves through
the use of GTL technology. We have also undertaken a number of technical and
marketing studies to assist in evaluating the economic viability of the
prospects.

OPERATIONS

Our net loss for the year was $21.1 million ($0.16 per share) compared to net
income in 2000 of $5.4 million ($0.05 per share). The net change year over year
of $26.5 million is attributable to a $14.0 million write down of our United
States properties under the ceiling test calculation in 2001 and the $12.2
million gain on the sale of our Russian properties recorded in 2000. As more
fully explained in Note 15 to our consolidated financial statements, included in
Item 8 herein, on application of United States GAAP an additional $10 million
write down of our China property and a $5.1 million write-off of capitalized
development costs in connection with our GTL prospects are required. No similar
write-downs are required under Canadian GAAP. Our cash flow from operating
activities for the year ended December 31, 2001 was $2.4 million, up from the
cash flow deficiency from operating activities of $11.8 million we experienced
in 2000. In 2001, we raised $18.2 million through private placements and the
exercise of warrants and incentive stock options ($47.7 million was raised in
2000 from similar sources). In 2001 we invested $40.5 million ($40.8 million in
2000), primarily in exploration and development activities.

PRODUCTION

At our South Midway Sunset field in California we have drilled 31 wells, 29 of
which are producing. We are currently producing approximately 400 net Bbls/d. In
the fourth quarter of 2001 we completed a pilot cyclic steam enhancement
project, which was very successful in more than doubling production rates in the
five wells that were treated. A full-scale cyclic steam project is now being
planned to commence in 2002. South Midway Sunset is primarily designed to
provide us with immediate cash flow from a low risk, low cost development
project with existing infrastructure. We own a 100% working interest and a 93%
net revenue interest in the project. Aera elected not to participate in this
project but receives royalties pursuant to the Aera exploration agreement.

As of the end of 2001 we have drilled 30 wells in the Spraberry field, which are
producing approximately 300 net Boe/d. All 30 wells have been completed in one
or more of the Wolfcamp zones but 5 wells still are awaiting their Spraberry
zone completions. We plan to start these completions in early 2002 and finish
them by the end of 2002. During the remainder of 2002, we may drill an
additional six to eight wells in the area known as Apache Flats where we have a
40% working interest before payout. To date we have drilled three wells in this
area that are producing 40 net Boe/d

South Midway Sunset and Spraberry are our only producing fields in the United
States. The substantial declines in oil and gas product prices during 2001 have
had significant impact on our operating profitability at these fields and have
made it necessary to provide a provision for impairment on the carrying value of
our United States evaluated oil and gas assets. We recorded an impairment
provision of $5 million at the end of the second quarter and an additional
provision of $9 million at the end of the third quarter. No further provision
was required at year-end.

In China, with the decision on both our projects to proceed to the development
stage, we commenced in early 2001 to record our production from our pilot wells
as income as opposed to crediting project carrying costs as was previously our
practice. At year end, 8 wells were producing at Dagang at a rate of 555 Bbls/d
and 2 wells at Daqing producing at 51 Bbls/d.

Production and revenues we generated in 2001 are detailed below. Although we
generated production revenue in 1999, it was all attributable to our former
Russian operations and, as a consequence, is not comparable.

24

Total revenue from our oil and gas operations was $9.1 million. Operating costs
we reported in our statement of income (loss) included allocated head office
engineering support of $1.1 million for 2001 (2000 -- $0.5 million).

PROJECT IDENTIFICATION COSTS

We remain committed to the geographical diversification of our oil and gas
activities. We follow the practice of expensing the costs we incur in pursuing
and investigating new projects as well as costs associated with investment
banking advice. During 2001, we incurred $6.2 million, up $2.5 million from the
$3.7 million incurred in 2000, in costs associated with international project
opportunities that we have rejected. Of the increase $1.4 million is
attributable to payments to investment bankers for assistance with financial and
strategic planning.

GENERAL AND ADMINISTRATION

We incurred general and administrative costs of $2.6 million during 2001, down
$0.3 million from the $2.9 million we incurred in 2000.

OTHER INCOME AND EXPENSES

Interest income represents income we earned on our excess cash balances held
during the year. The decrease of approximately $0.4 million from 2000 arises
from a reduction of our cash balances and interest rates during 2001. Russian
litigation costs ceased in mid 2000 with the successful resolution of our
dispute with our Russian joint venture partner and divestiture of our Russian
projects. Depletion and depreciation is up $2.9 million from 2000 due to the
inclusion of production from our US properties for a full year and the inclusion
of production from China in income in 2001.

INCOME TAXES

We have significant tax losses available to carry forward and reduce taxes
otherwise payable. Details of these losses are in Note 10 to the consolidated
financial statements included herein under Item 8. Given the uncertainty as to
the utilization of these tax loss carry-forwards, we have followed the practice
of recording a provision against the tax benefit asset resulting from these
losses.

EXPLORATION AND DEVELOPMENT ACTIVITIES

During 2001 we continued our exploration program in the San Joaquin Valley of
Southern California on acreage primarily acquired under the Aera exploration
agreement. Using the extensive proprietary

25

seismic and technical databases owned by Aera and supplemented by us, we have
identified over 40 drillable prospects in 18 Areas of Mutual Interest ("AMIs")
covering approximately 72,800 acres. Aera has elected to participate in 12 of
these AMIs (in which we have working interest ranging from 12.5% to 50%); in 3
AMIs Aera elected not to participate and on 2 AMIs Aera has yet to make an
election. In the remaining AMI we have both elected not to pursue the prospect
and have farmed it out retaining an overriding royalty interest. We spud our
first deep gas exploration well at Northwest Lost Hills in Kern County, results
of which will not be known until the second quarter 2002. In addition, we
drilled 2 other exploration wells in southern California, which were
unsuccessful, and were abandoned. See Items 1 and 2. "Description of Business
and Properties -- Oil and Gas Properties -- California -- Aera Exploration
Agreement". At South Midway Sunset we continued our drilling program by drilling
10 more development wells, all commercial oil producers. (See above discussion
under "Production") Additionally we initiated a pilot cyclic steam enhancement
project, resulting in a full-scale steam project planned to commence is 2002. We
acquired overriding royalties, ranging from 1.75% to 6.58%, in the deep rights
of certain leases of the Aera exploration agreement.

In Texas, we drilled an additional 14 producing wells in the Spraberry Trend
acreage in west Texas. (see above discussion under "Production") In 2001, we
spud 2 wells in the Cresslan Ranch prospect within the Bossier Trend in east
Texas, both of which encountered gas shows and are currently being prepared for
stimulation and testing. We continue to increase our leased acreage in the
Bossier area.

In Kentucky, through a participation agreement entered into in March 2001, we
drilled 3 exploration wells. Two are currently awaiting stimulation before
testing and one well is suspended.

At our Dagang Project in China, we completed our pilot-testing phase in February
2001 and later in the year submitted our overall development plan to the Chinese
authorities for their approval, which is expected in the first half of 2002. In
the interim, we continue to operate the pilot wells with production revenue
accruing to us. At our Daqing Project, our overall development plan was approved
in February 2001 and we resumed operatorship and rights to revenues March 1
2001. The resumption of our rights to revenues at Daqing represents the primary
difference between our China oil production reported below of 102,708 net
barrels and the China oil production of 165,599 in 2001. Our Daqing Project is
small by international standards and negotiations with CNPC for additional
blocks to be included in the contract area have proved unsuccessful and after an
internal review our China projects, and based on our shift towards major gas
development in China we put the Daqing project up for disposal. Effective
January 22, 2002 we disposed of the project for $2.4 million and an overriding
royalty on future production.

With the decision to proceed to the development stage, beginning in 2001 for
accounting purposes, all oil revenues and related operating costs are included
in our statement of loss and deficit. For Daqing this was March 1, 2001. The
following summarizes the production and revenue we realized from the pilot
testing phase of our Dagang Project during 2000 and 1999. Prior to deciding to
proceed to the development phase, this revenue was credited to the China cost
pool for accounting purposes. During this same period under a special
arrangement with CNPC we had relinquished our operations of the Daqing project
and therefore we show no pilot test production for that time frame. All sales of
oil are at or about WTI less approximately $2.00 for quality and transportation.
We receive all proceeds in U.S. dollars offshore China.

26

Total capital spending on oil and gas operations, including non-cash
transactions, during 2001 compared to 2000 was as follows:

GAS-TO-LIQUIDS

In 2000, we acquired a master license from Syntroleum permitting us to use
Syntroleum's proprietary GTL process in an unlimited number of GTL projects
around the world except North America, China and India. We have identified and
are aggressively pursuing projects in Qatar and Egypt. To date we have
undertaken detailed feasibility studies for the construction, operation and cost
of GTL plants and conducted marketing and transportation feasibility studies for
Europe and the Asia- Pacific regions. Costs of $5.1 million ($3.9 million
incurred in 2001) incurred in connection with the ongoing negotiations for these
projects and the costs of our feasibility studies have been capitalized. For
United States GAAP purposes these costs have been written off. See Items 1 and
2. "Description of Business and Properties -- Gas-to-Liquids Projects".

In 2000, we invested $2 million in Syntroleum's Sweetwater project to be located
on the Burrup Peninsula in Western Australia. An additional $19 million
investment was agreed, contingent on Syntroleum securing project financing. We
have since identified two larger GTL project opportunities in Qatar and Egypt,
which may affect our continuing participation in Sweetwater. However, no
decision has been reached at this time.

LIQUIDITY AND CAPITAL RESOURCES

In 2001 we commenced an aggressive capital expenditure program. For the year
ended December 31, 2001 we expended $ 36.8 million for acquisition, exploration
and development activities and an additional $3.9 million to further our GTL
business. To facilitate these expenditures we raised $18 million through private
placement.

In 2002 we plan to incur capital expenditures of approximately $45 million of
which $25 million is allocated to our exploration and development activities and
an additional $20 million is allocated to furthering our GTL activities. Actual
exploration and development expenditures in California and Texas will be
contingent upon continued drilling success at Northwest Lost Hills and Bossier.
Actual GTL expenditures will be primarily contingent upon the successful outcome
of our negotiations in Qatar and our future role, if any, in the Sweetwater
project.

At current oil and gas prices and given our cash on hand at year end no
additional funding will be required to fund our current level of administrative
and engineering costs through 2002. Our $1 million convertible debenture is due
in August 2002, if the holders choose not to convert.

27

We currently do not have the financial resources to carry out our planned 2002
capital expenditures. It will be necessary for us to raise the funds through the
issuance of equity or debt securities, project financing, additional joint
ventures with third parties, disposal of non-core asset or a combination of the
foregoing. While we have had success in the past in raising funds through the
issue of equity, we can give no assurance that we will be able to in the future.
Should we be unable to raise the necessary funds to carry out our 2002 budget it
will be necessary to prioritize our activities, which may result in our delaying
and potentially losing some valuable business opportunities. Any such delay or
loss may have a material adverse effect on our ability to successfully implement
our corporate strategy.

Subsequent to year-end we raised $2.4 million from disposal of our Daqing
project in China.

OFF BALANCE SHEET DISCLAIMER:

At December 31, 2001 and 2000, we did not have any relationships with
unconsolidated entities or financial partnerships, such as entities often
referred to as structured finance or special purpose entities, which would have
been established for the purpose of facilitating off-balance sheet arrangements
or other contractually narrow or limited purposes. In addition, we do not engage
in trading activities involving non-exchange traded contracts. As such, we are
not materially exposed to any financing, liquidity, market or credit risk that
could arise if we had engaged in such relationships. We do not have
relationships and transactions with persons or entities that derive benefits
from their non-independent relationship with us or our related parties except as
disclosed herein.

YEAR ENDED DECEMBER 31, 2000

OVERVIEW

During 2000, we concentrated our efforts on developing drillable prospects in
the San Joaquin Valley of California on acreage covered by the Aera exploration
agreement and on additional acreage we acquired there. To date, we have
identified six drillable prospects. We have selected a location for our first
deep-gas well at Northwest Lost Hills and, depending on rig availability, we
plan to spud the well during the second quarter of 2001. During the second
quarter of 2000, we commenced a drilling program in the South Midway Sunset area
and, by year-end, we had drilled 21 wells. We commenced commercial production
during the third quarter.

In 2000, we secured a 62.5% interest (96% interest in the first four wells) in
9,100 gross (5,700 net) acres in the Spraberry Trend of the West Texas Permian
Basin. By year-end, we had spudded 16 wells. Our interest in the play decreases
to 50% after payout. During the fourth quarter of 2000 and the first two months
of 2001, we acquired an interest in over 28,400 gross (20,700 net) acres in the
Bossier sands in East Texas, where we expect to commence drilling in the third
quarter of 2001.

At our two projects in China, we concentrated our efforts on completing the
pilot testing phase of the Dagang Project and obtaining approval by the Chinese
government for our overall development plan at our Daqing Project, which we
received in February, 2001. Implementation of the plan is scheduled to commence
in the third quarter of 2001. At our Dagang Project, the pilot testing phase was
completed successfully in February 2001. We now plan to proceed with the
development phase which will require the submission of an overall development
plan to the Chinese government for approval. We expect to submit it in the
second half of 2001.

During 2000, we acquired a master license from Syntroleum permitting us to use
Syntroleum's proprietary GTL technology and on October 5, 2000 we signed a
letter of intent with Syntroleum to acquire a 13% non-recourse partnership
interest in Syntroleum's Sweetwater GTL project under development in Western
Australia.

In August, 2000 we were successful in negotiating a settlement of our legal
dispute with our Russian partner at Tura in Western Siberia. In consideration
for relinquishing our entire interest in Tura and the adjacent Radonezh Project,
we received $28.2 million, net of settlement and severance costs of $0.8
million.
28

OPERATIONS

Our net income for the year was $5.4 million ($0.05 per share) compared to a
loss in 1999 of $7.8 million ($0.08 per share). We attribute the improvement
from 1999 to the commencement of initial production from our properties in
California and Texas and from the gain of $12.2 million we realized from the
settlement of our Russian dispute. Our cash flow deficiency from operating
activities for the year ended December 31, 2000 was $11.8 million, up 90% from
the cash flow deficiency from operating activities of $6.2 million we
experienced in 1999. In 2000, we raised $47.7 million through private placements
and exercise of warrants and incentive stock options ($0.7 million in 1999) and
invested $40.8 million ($10.7 million in 1999) in capital assets. By the end of
2000, we were able to sell, without further loss, the last of our equipment
originally destined for Russia.

PRODUCTION

In 2000, we commenced production at our South Midway Sunset field in California
and at our Spraberry field in West Texas. At South Midway Sunset we drilled and
completed our first well and went into production in July 2000. By year-end we
had drilled a total of 21 wells of which 19 were completed and 17 in production.
The remaining two completed wells were placed on production in January 2001. The
two uncompleted development wells were dry, one of which we plan to use as a
water disposal well. At the Spraberry Trend, we drilled 16 wells in 2000, of
which 10 were completed and on production by year-end, with the remaining six
wells completed and placed on production in early 2001. To date in 2001, we have
drilled an additional six development wells, of which one was placed on
production in February, 2001.

Production and revenues we generated in 2000 are detailed below. Although we
generated production revenue in 1999 and 1998, it was all attributable to our
former Russian operations and, as a consequence, is not comparable.

Total revenue from our oil and gas operations was $851,000. Our operating costs
at South Midway Sunset were unusually high due to facility rental costs
associated with start-up operations. We expect to reduce our operating costs at
South Midway Sunset to the $4.00 per barrel range during the second quarter of
2001. Operating costs we reported in our statement of income include allocated
head office engineering support costs of $0.5 million. Depletion, depreciation
and amortization costs are high due to the nature of the South Midway Sunset and
Spraberry Trend projects. While South Midway Sunset and Spraberry Trend require
high development and facility costs to exploit limited reserves, both provide
good economic returns at current oil and natural gas prices.

29

PROJECT IDENTIFICATION COSTS

We remain committed to the geographical diversification of our oil and gas
activities. We follow the practice of expensing the costs we incur in pursuing
and investigating new projects. With the acquisition of our Syntroleum master
license, we have intensified our search for new international oil and gas and
GTL projects. During 2000, we incurred $3.7 million, up $2.0 million from the
$1.7 million incurred in 1999, in costs associated with international project
opportunities that we have rejected or that we were still investigating at
year-end. Once we obtain rights or interests in a new project we capitalize the
costs we incurred in obtaining the project.

GENERAL AND ADMINISTRATION

We incurred general and administrative costs of $2.8 million during 2000, up
$0.2 million from the $2.6 million we incurred in 1999. We attribute the bulk of
the increase to the costs associated with listing on NASDAQ in 2000.

OTHER INCOME AND EXPENSES

Interest income represents income we earned on our excess cash balances held
during the year. The increase of approximately $0.5 million during 2000 arises
from the additional funds available from two private placements we completed
during the year and from the divesture of our Russian projects. Russian
litigation costs (down approximately $0.3 million from 1999), depletion and
depreciation (down $1.3 million from 1999) and asset write downs (down $2.5
million from 1999) all result from the divesture of our Russian projects and the
settlement of our legal dispute with our Russian partner in August 2000.

INCOME TAXES

We have significant tax losses available to carry forward and reduce taxes
otherwise payable. Given the uncertainty as to the utilization of these tax loss
carry-forwards, we have followed the practice of recording a provision against
the tax benefit asset resulting from these losses. In 2000, our expected income
tax expense on the income reported on our statement of income has been reduced
by the benefit of tax assets not previously recorded.

EXPLORATION AND DEVELOPMENT ACTIVITIES

During 2000, we carried out an extensive exploration program in the San Joaquin
Valley on acreage primarily acquired under our Aera exploration agreement. We
participated in an 80,000 acre 3-D seismic shoot, the largest ever carried out
in the San Joaquin Valley. We purchased an additional 7,000 acres of 3-D seismic
previously shot in the same area. We also continued interpreting over 2,000
miles of 2-D seismic acquired in 1999. We submitted preliminary prospects to
Aera for its review in 14 areas covered by the Aera exploration agreement. We
are developing numerous drillable prospects within those preliminary prospect
areas and, during 2000, we submitted six drillable prospects to Aera. At South
Midway Sunset, where we have a 100% interest, we commenced a drilling program,
details of which are discussed above under "Production". In addition to the
South Midway Sunset drilling program, we drilled three other exploration wells
in the San Joaquin Valley during 2000, two of which were dry and abandoned. We
are still testing the third well to determine its commercial potential. We
identified the location of our first deep gas well at Northwest Lost Hills and
we expect to spud the well during the second quarter of 2001.

In Texas, we drilled 16 successful wells in our Spraberry Trend acreage in West
Texas by year-end and an additional four wells during the first two months of
2001. Through a series of transactions in late 2000 and early 2001, we were
successful in acquiring an interest in over 28,400 gross (20,700 net) acres in
the Bossier gas sands in East Texas. We expect to commence drilling at Bossier
during the third quarter of 2001.

30

At our Dagang Project in China, we completed our pilot testing phase in
February, 2001. During 2000, as part of the pilot testing phase, we placed in
production four new wells. We placed our initial well on water injection late in
2000 to evaluate the waterflood potential of the field. We also placed on
production a fifth well in early 2001. We have decided to proceed to the
development stage of our Dagang Project, which will require the submission of an
overall development plan to the Chinese government for approval. We expect to
submit it to the Chinese government during the second half of 2001. In the
interim, we will continue to operate the pilot wells with production revenue
accruing to us. At our Daqing Project, our overall development plan was approved
in February, 2001 and we expect to start implementing it during the third
quarter of 2001. Although we completed the pilot testing phase of the Daqing
Project in 1998, we delayed submitting our overall development plan to the
Chinese government because of low world oil prices and in order to focus our
attention on our Dagang Project. In the interim, we agreed with CNPC to
temporarily cede our operatorship of the Zhaozhou field pending completion and
approval of our overall development plan for the Daqing Project. Having
submitted and received approval for the Daqing Project, we expect to resume our
role as operator during the first quarter of 2001.

The following summarizes the production and revenue we realized from the pilot
testing phase of our Dagang Project. Prior to deciding to proceed to the
development phase, this revenue was credited to the China cost pool for
accounting purposes. All sales of oil are at or about WTI less approximately
$2.00 for quality and transportation. We receive all proceeds in U.S. dollars
offshore China.

Our total capital spending on oil and gas operations, including non-cash
transactions, during 2000, compared to 1999, was as follows:

GAS-TO-LIQUIDS

During 2000, we acquired a master license from Syntroleum which allows us to use
Syntroleum's proprietary GTL technology in an unlimited number of GTL projects
throughout the world excluding North America, China and India. The Syntroleum
GTL process converts natural gas into synthetic liquid hydrocarbons that can be
utilized to develop cleaner-burning diesel fuel and other synthetic petroleum
products. We have commenced engineering studies and review of several potential
sites for our first GTL

31

plant and we are in advanced discussions with national petroleum corporations in
the Middle East and Asia.

On October 5, 2000, we signed a letter of intent with Syntroleum to acquire a
13% non-recourse partnership interest in Syntroleum's Sweetwater GTL project
under development in Western Australia. The plant, which will be located on the
Burrup Peninsula in Western Australia, will convert natural gas contracted from
the North West Shelf Venture Partners into ultra clean synthetic specialty
products, such as lubricants, industrial fuel and paraffins, as well as
synthetic fuels.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We have exploration and development projects in the United States and China. Our
projects are at various stages and, like all exploration companies in the oil
and gas industry, we are exposed to the significant risk that our exploration
activities will not necessarily result in a discovery of economically
extractable reserves.

We currently have limited production. Until June, 1999, we had a successful
producing project in Russia, but legal actions initiated in the Russian courts
by our Russian joint venture partner deprived us of the right to operate the
field and to realize any continuing return on our investment. As a result, we
sold our interest in the project in August 2000. Oil and gas revenue reported
before 2000 was generated from our share of production from the Russian project.

Given our limited production, we have limited exposure to commodity price risks.
We are exposed to the risk that we may require a provision for impairment as to
the carrying value of our oil and gas assets. The carrying value of our
capitalized oil and gas assets is compared quarterly to the estimated
recoverable value of our proved reserves based on period-end commodity prices,
unescalated. We are exposed to the risk that we will be unable to engage
competent cost-effective contractors and suppliers for our operations, risks
that damage to, or malfunction of, our equipment will hinder our ability to
carry out our exploration activities and risks that foreign laws may not
adequately protect our interests in disputes with foreign partners and others.

In the international petroleum industry, most production is bought and sold in
United States currency or with reference to United States currency. Accordingly,
we do not expect to face foreign exchange risks if and when we commence large
scale commercial production. Most of our business transactions are conducted in
United States currency in the countries in which we operate.

We currently have minimal debt obligations and, therefore, we do not believe
that we face any undue financial risk from interest rate fluctuations and we are
not currently involved in any transactions of a hedging nature.

32

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND RELATED INFORMATION

33

AUDITORS' REPORT

To the Shareholders of
IVANHOE ENERGY INC.:

We have audited the consolidated balance sheets of Ivanhoe Energy Inc. as at
December 31, 2001 and 2000 and the consolidated statements of loss (income) and
deficit and cash flow for each of the years in the three year period ended
December 31, 2001. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

With respect to the consolidated financial statements for each of the years in
the two year period ended December 31, 2001 we conducted our audit in accordance
with Canadian generally accepted auditing standards, and United States generally
accepted auditing standards. With respect to the consolidated financial
statements for the year ended December 31, 1999, we conducted our audit in
accordance with Canadian 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. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2001
and 2000 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2001 in accordance with
Canadian generally accepted accounting principles.

Calgary, Alberta (signed) Deloitte & Touche LLP
February 8, 2002 Chartered Accountants

COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA -- U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when the financial
statements are affected by conditions and events that cast uncertainty as to the
Company's ability to carry out and complete planned activities without raising
additional financing, as described in Note 1 to the financial statements. Our
report to the shareholders dated February 8, 2002 is expressed in accordance
with Canadian reporting standards which do not permit a reference to such events
and conditions in the auditor's report when these are adequately disclosed in
the financial statements.

In addition, in the United States, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph) outlining
changes in accounting principles that have been implemented in the financial
statements. As discussed in Note 11 to the financial statements, in 2001 the
Company changed its method of computing diluted earnings per share to conform to
the new Canadian Institute of Chartered Accountants Handbook recommendations
section 3500.

Calgary, Alberta (signed) Deloitte & Touche LLP
February 8, 2002 Chartered Accountants

34

IVANHOE ENERGY INC.

CONSOLIDATED BALANCE SHEETS
(STATED IN THOUSANDS OF U.S. DOLLARS)

APPROVED BY THE BOARD:

(signed) David Martin (signed) Leon Daniel
Director Director

35

IVANHOE ENERGY INC.
CONSOLIDATED STATEMENTS OF LOSS (INCOME) AND DEFICIT
(STATED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE DATA)

36

IVANHOE ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOW
(STATED IN THOUSANDS OF U.S. DOLLARS)

37

IVANHOE ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(EXPRESSED IN U.S. DOLLARS WITH AMOUNTS IN TABLES BEING IN THOUSANDS, EXCEPT PER
SHARE DATA)

1. NATURE OF OPERATIONS

Ivanhoe Energy Inc., a Canadian company, and its subsidiaries are focused
internationally on three major strategies: 1) exploration and development of
hydrocarbons 2) enhanced oil recovery and 3) the application of gas-to-liquids
technology. Operations are currently carried out in the United States and China.

The Company's activities contemplate significant capital expenditures to develop
its properties and projects. Significant financing will need to be raised
through equity, debt financing and joint venture partner participation in order
to complete the planned activities. In the event that such financing is not
available to the Company, it will be necessary to prioritize activities, which
may result in delaying and potentially losing business opportunities and causing
potential impairment to recorded assets.

2. SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements have been prepared in accordance with
generally accepted accounting principles ("GAAP") in Canada. The consolidated
financial statements also conform in all material respects to United States
GAAP, except for the following matters for which details are provided in the
referenced notes: -- the price per share used to record the acquisition of
royalty interests (Note 3); -- reduction of the deficit as at December 31, 1998
(Note 5); -- net loss (income) for the year as a result of an additional ceiling
test required under United States GAAP and the requirement to write-off
capitalized development costs incurred in connection with our GTL prospects, net
loss (income) per share calculations, and additional disclosures required under
United States GAAP (Note 15).

The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts and other disclosures in these
consolidated financial statements. Actual results may differ from those
estimates.

PRINCIPLES OF CONSOLIDATION

These consolidated financial statements include the accounts of Ivanhoe Energy
Inc. and its subsidiaries, all of which are wholly owned.

All inter-company transactions and balances have been eliminated for the
purposes of these consolidated financial statements.

FOREIGN CURRENCY TRANSLATION

The Company uses the United States Dollar as its functional currency since it is
the currency of the economic environments in which the Company and its
subsidiaries operate. Monetary assets and liabilities denominated in foreign
currencies are converted at the exchange rate in effect at the balance sheet
date and non-monetary assets and liabilities at the exchange rates in effect at
the time of acquisition or issue. Revenues and expenses are converted at rates
approximating exchange rates in effect at the time of the transactions. Exchange
gains or losses resulting from the translation of foreign currency amounts are
reflected in operations.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include short-term money market instruments with terms
to maturity, at the date of issue, not exceeding 90 days.

38

FINANCIAL INSTRUMENTS

The fair value of the Company's cash, accounts receivable, notes receivable,
accounts payable and accrued liabilities approximates the carrying values due to
the immediate or short-term maturity of these financial instruments.

The estimated fair value of the convertible debenture at December 31, 2001 is
approximately $1,442,000, (December 31, 2000 -- $1,790,000).

OIL AND GAS PROPERTIES

The Company follows the full cost method of accounting for oil and gas
operations whereby all exploration and development expenditures are capitalized
on a country-by-country cost centre basis. Such expenditures include land
acquisition costs, geological and geophysical expenses, carrying charges for
unproved properties, costs of drilling both productive and non-productive wells,
gathering and production facilities and equipment, and financing and
administrative costs related to capital projects. Proceeds from sales of oil and
gas properties are recorded as reductions of capitalized costs, unless such
amounts would significantly alter the rate of depreciation and depletion,
whereupon gains or losses would be recognized in income. Maintenance and repair
costs are expensed as incurred, while improvements and major renovations are
capitalized.

Costs of oil and gas properties accumulated within each cost centre, including a
provision for future development costs, are depleted using the unit of
production method based on estimated proved reserves. Significant development
projects and expenditures on exploration properties are excluded from the
depletion calculation until evaluated. These excluded costs are evaluated
periodically for impairment.

Royalties acquired are included in oil and gas properties and recorded at cost.

Depletable costs, accumulated in each cost centre, net of depletion provided,
future income taxes and accumulated site restoration costs, are compared
annually to the non-discounted estimated future net revenues from proved
reserves (based on year-end non-escalated prices), net of estimated
administration and carrying costs, and related production and income taxes
("ceiling test"). Any accumulated costs in excess of the calculated ceiling test
are charged to operations.

PROVISION FOR FUTURE SITE RESTORATION

The Company has developed an estimate for future site restoration and
abandonment costs and is amortizing this estimate to operations using the
unit-of-production method based upon estimated proved reserves. The provision is
included with depletion and depreciation expense.

FURNITURE AND FIXTURES

Furniture and fixtures are stated at cost. Depreciation is provided on a
straight-line basis over the estimated useful life of the respective assets, at
rates ranging from three to ten years.

PETROLEUM AND NATURAL GAS REVENUE

Sales of crude oil and natural gas are recognized in the period in which the
product is delivered to the customer.

LOSS (INCOME) PER SHARE

The loss (income) per share is computed on the basis of the weighted average
number of shares outstanding during each year. Effective January 1, 2001, the
Company adopted, retroactively, the treasury stock method to determine diluted
earnings per share (See Note 11).

39

INCOME TAXES

The Company follows the liability method of accounting for future income taxes,
which it adopted retroactively in the year ended December 31, 2000. Under the
liability method, future income taxes are recognized to reflect the expected
future tax consequences arising from tax loss carry-forwards and temporary
differences between the carrying value and the tax basis of the Company's assets
and liabilities.

STOCK BASED COMPENSATION PLAN

The Company has an Employees' and Directors' Equity Incentive Plan consisting of
stock option, bonus and share purchase incentives (Note 5). Options are granted
at market price and no compensation expenses are recognized when stock options
are issued or exercised. Consideration paid upon exercise of stock options is
credited to share capital. Compensation expenses are recognized when shares are
issued from the stock bonus plan. The share purchase portion of the plan has not
yet been activated.

3. OIL AND GAS PROPERTIES, EQUIPMENT AND GTL INVESTMENTS

Capital assets categorized by geographic location are as follows:

Costs as at December 31, 2001 of $40,267,000 (2000 -- $24,822,000; 1999 --
$12,767,000) related to unevaluated oil and gas properties are excluded from the
depletable cost pools.

For the year ended December 31, 2001 general and administrative expenses related
directly to acquisition, exploration, development and GTL activities of
$3,636,000 (2000 -- $1,549,000; 1999 -- $898,000) were capitalized.

GAS-TO-LIQUIDS

During 2000, the Company acquired a master license from Syntroleum Corporation
permitting the Company to use Syntroleum's proprietary gas-to-liquid process
("GTL") in an unlimited number of GTL projects around the world except North
America, China and India. The Syntroleum process converts natural gas into
synthetic liquid hydrocarbons that can be utilized to develop, among other
things, cleaner-burning diesel fuel. The Company views the process as holding
significant potential for monetizing uneconomic stranded natural gas reserves in
large gas-prone regions of the world.

40

On October 5, 2000, the Company signed a letter of intent with Syntroleum to
acquire a 13% non-recourse partnership interest in Syntroleum's Sweetwater GTL
project in Western Australia. Under the terms of the letter of intent, the
Company's 13% interest will cost a total of $21,000,000, of which $2,000,000 has
been paid and will be used by Syntroleum, solely to fund front-end engineering
and other project engineering expenses. Payment of the remaining $19,000,000 is
subject to satisfaction of various conditions, including Syntroleum obtaining
project financing. The Company's participation does not require any further
financial commitments and entitles the Company to participate in 13% of the
project cash flow each year. Syntroleum is continuing the process of refining
the cost structure of the GTL facilities and securing financing for the project.

The Company has undertaken detailed project feasibility studies for the
construction, operation and cost of world class GTL plants in both Qatar and
Egypt. In addition, the Company conducted two marketing and one transportation
feasibility studies. Marketing studies were conducted for both Europe and the
Asia-Pacific regions for GTL diesel and naphtha. Markets within these regions
were identified and premiums for the GTL ultra clean fuels were estimated.
Product forecasts from these studies will be used as the basis for evaluating
the commerciality of each of the GTL projects. All cost associated with these
two projects have been capitalized.

Recovery of the GTL costs capitalized is dependent upon finalizing contracts to
access natural gas reserves in the respective countries and the successful
completion of GTL processing plants. For United States GAAP purposes development
costs associated with the Company's GTL prospects of $5,142,000 have been
written off.

UNITED STATES

In 1998, the Company acquired rights to an exploration agreement with Aera
Energy LLC ("Aera") in an area of more than 250,000 acres in the Southern San
Joaquin Valley in California. The Aera Exploration Agreement ("Agreement") gave
the Company the right, which expired on September 15, 2001, access to all of
Aera's exploration, seismic and technical data in the region for the purpose of
identifying drillable exploration prospects within the exclusive area. The
Agreement provided the Company the right to a working interest ownership in all
drillable prospects in which Aera elects to participate equal to a minimum of
12.5% and a maximum of 75%. In those prospects in which Aera elects not to
participate the Company has the right to proceed with a 100% working interest
and to seek other joint venture partners. Aera has the right to act as the
operator for any drillable prospects in which Area elects to participate.

During the term of the Agreement, the Company submitted to Aera 18 prospect
Areas of Mutual Interest ("AMIs") containing a total of over 40 prospects. Aera
has elected to participate in 12 AMIs in which the Company will have working
interests ranging from 12.5% to 50%. In the 3 AMIs where Aera has elected not to
participate, the Company will have a 100% working interest. In 2 of the AMIs
Aera has not yet made an election to participate. In the remaining AMI neither
Aera nor the Company has elected to participate and subsequent to year end have
farmed out the prospect, retaining an overriding royalty interest.

In addition to prospects under the Agreement the Company has acquired other
percentage interests in Southern California, West Texas, Kentucky and the
Bossier Trend in east Texas.

The Company has leased mineral rights in 58,000 gross (44,000 net) acres in the
Bossier Trend in east Texas and has entered into joint venture agreements with a
subsidiary of Unocal Corp. ("Unocal") under which Unocal will earn a 50%
interest in the Company's holdings by expending the next $10 million of costs
associated with exploration and development of prospects.

CHINA

During the year the Company held two production-sharing contracts to develop
existing oil fields in the Daqing and Dagang regions of the People's Republic of
China. Basically the Company incurs 100% of the

41

costs to earn approximately 82% of the production, before recovery of costs
incurred, reverting to a 49% share post recovery.

Each contract calls for the planning and completion of a pilot testing phase to
assess the technological and economic viability of the project, followed by a
full field development plan and implementation.

At the Company's Dagang project, the pilot testing phase was completed in
February 2001. Nippon Oil Exploration Limited of Japan, earned a 20% working
interest in the Company's interest in the project by funding a disproportionate
share of the Dagang pilot testing expenditures. In August 2001 Nippon decided to
withdraw from the project and their interest reverted back to the Company. The
decision was made to proceed with the preparation of the development plan for
submission to CNPC. Submission of the final draft and subsequent approval is
expected in 2002. During the development plan preparation and approval process
the Company will continue operatorship of the Dagang project.

At Daqing, the pilot program was completed successfully in 1998. While the
decision was made to continue on to the field development plan, the Company
chose to delay the process and, by agreement, CNPC took over operatorship of the
field and the right to all revenue generated and responsibility for all costs
incurred. The field development plan was completed in 2000 and approved by the
relevant regulatory agencies in February 2001. Operatorship reverted back to the
Company on March 1, 2001. During 2001 the Company negotiated with CNPC for
additional blocks to be included in the contract area. Negotiations were
unsuccessful and after an internal review of the Company's China projects, and
the decision to concentrate on major gas developments in China, the Daqing
project was put up for disposal. Effective January 22, 2002 the Company was
successful in disposing of the project for $2,400,000 and an overriding royalty
on future production. (Note 13)

During the pilot testing phase at Dagang and Daqing, for accounting purposes,
all production costs and revenues were capitalized. With the evaluation stage
completed and the decision made to enter the development and implementation
stage, all operating results beginning January 1, 2001 for Dagang and March 1,
2001 for Daqing are included in the Company's operations.

During the year the Company signed two memorandums of understanding with
PetroChina Company Limited ("PetroChina"), which gives the Company the exclusive
right to negotiate petroleum contracts with PetroChina to develop and exploit
the oil and gas resources in three key blocks within the Sichuan basin, China's
largest gas-producing region. The Company signed Joint Study Agreements with
PetroChina covering the three blocks and outlining the joint activities and
technical requirements of both parties prior to entering into contract
negotiations. At year-end the Company was still in the process of assessing the
oil and gas resources and potential development plan.

OVERRIDING ROYALTIES

Through a series of transactions the Company has acquired overriding royalties
in AMI prospects in California ranging from 1.4637% to 6.58% in consideration
for $860,000 cash and the issuance of 2,885,000 common shares at an aggregate
ascribed value of $8,032,000, being 1,562,000 common shares at $2.02
(Cdn.$2.98); 523,000 common shares at $1.76 (Cdn.$2.55) and 800,000 common
shares at $4.94 (Cdn.$7.59). Of the total consideration paid in 2001, $900,000
was allocated to lease acquisition and $200,000 to accounts receivable.

For United States GAAP purposes, the aggregate value attributed to the royalty
acquisitions is $1,358,000 higher, due to the difference between the value
ascribed to the shares issued between Canadian and United States GAAP, primarily
resulting from differences in the recognition of effective dates of the
transactions.

4. CONVERTIBLE DEBENTURE

The $1,000,000 unsecured convertible debenture bears interest at United States
prime plus 2.5%, is due on the earlier of August 4, 2002 or within 90 days
following written demand, and is convertible into

42

common shares (principal and interest, accrued and unpaid, all or in part) of
the Company at Cdn.$2.75 per share up to August 4, 2002.

5. SHARE CAPITAL

The authorized capital of the Company consists of an unlimited number of common
shares without par value and an unlimited number of preferred shares without par
value.

The total number of issued and outstanding common shares is as follows:

The December 31, 2001 share dollar amount is net of loans of $409,000 (December
31, 2000 -- $236,000) advanced to an employee and two directors to assist in the
exercise of incentive stock options as permitted under the Employees' and
Directors' Equity Incentive Plan.

PRIVATE PLACEMENTS AND SHARE PURCHASE WARRANTS

Under a private placement in October 2001, the Company issued 11,260,000 common
shares at $1.60, net of expenses of $113,000.

During 2000, the Company issued common shares under two private placements. In
January and February 2000, the Company issued 6,250,000 units, each unit
consisting of one common share and one share purchase warrant, for net proceeds
of $14,014,000. Each two warrants were exercisable into one common share at
Cdn.$4.00 until the first anniversary date of the private placement. At December
31, 2001 all of these warrants were exercised. On October 17, 2000, the Company
issued 5,000,000 units, each unit consisting of one common share and one share
purchase warrant, for net proceeds of $24,584,000. Each two warrants were
exercisable into one common share at $5.375 until October 17, 2002. At December
31, 2001, all of the warrants remain outstanding for purchase of 2,500,000
common shares.

REDUCTION OF STATED CAPITAL

The shareholders approved, on June 22, 1999, the reduction of stated capital in
respect of the common shares by an amount of $74,455,000 being equal to the
accumulated deficit as at December 31, 1998. Under United States GAAP, a
reduction of the deficit such as this is not recognized except in the case of

43

a quasi reorganization. The effect of this is that under United States GAAP,
share capital and deficit each are increased by $74,455,000 at December 31, 2001
and 2000.

EQUITY INCENTIVE PLAN

The Company has an Employees' and Directors' Equity Incentive Plan under which
it can grant stock options to directors, officers and employees to purchase
common shares, issue common shares to directors and employees for bonus awards
and issue shares under a share purchase plan for employees.

Stock options are issued at the quoted market value on the date of the grant,
are conditional on continuing employment and vest at the discretion of the Board
of Directors. Options granted vest over a four year period and expire five years
from the date of issue except those granted prior to March 1, 1999 which vest
over a two year period and expire ten years from date of issue.

Following is a summary of the stock option portion of the Company's Equity
Incentive Plan, including changes during the years ended:

The following table summarizes information respecting stock options outstanding
at December 31, 2001:

Subsequent to December 31, 2001, the Company issued 201,000 common shares from
the bonus awards portion of the Equity Incentive Plan, to directors, officers
and employees as part of a deferred compensation program implemented for the
fourth quarter 2001. The total compensation amount is accrued in the 2001
statement of loss (income) and deficit.

6. RETIREMENT PLAN

In 2001 the Company adopted a defined contribution retirement or thrift plan
(401(k) Plan) to assist United States employees in providing for retirement or
other future financial needs. Employees' contributions (up to the maximum
allowed by United States tax laws) are matched 50% by the Company in 2001 and
increasing 10% per year thereafter to a maximum of a 100%. The cost of Company
contributions to the plan during 2001 amounted to $78,000.

44

7. SEGMENT INFORMATION

Geographic segment results from operations for the years ended December 31,
2001, 2000 and 1999 are detailed below. The Company maintains a corporate office
in Canada with its operational office in the USA. For this section any amounts
for Canada are included in the USA segment.

YEAR ENDED DECEMBER 31, 2000
------------------------------
U.S. CHINA TOTAL
------- ------- --------

During 2001, three customers accounted for 100% of the total sales in the United
States, being 49%, 40% and 11% respectively. In China 100% of the 2001 sales
were made to the China National Petroleum Corporation.

In the United States during 2000, three customers accounted for 96% of total
sales being 44%, 40% and 12% respectively. In 1999, the Company derived 96% of
its Russia sales from two customers, being 85% and 11% respectively.

8. PROVISION FOR IMPAIRMENT

Provision for impairment amounts determined under Canadian GAAP include the
following:

On application of United States GAAP an additional provision for impairment,
with respect to the Company's China properties, of $10,000,000 is required. No
impairment provisions were required for 2000 or 1999. (See Note 15 -- U.S. GAAP
Disclosures)

9. GAIN ON SALE OF RUSSIAN PROJECTS

In August 2000, a negotiated settlement was reached resulting in the disposition
of the Company's Russian projects for cash proceeds of $28,182,000, net of
$840,000 of settlement and severance costs. The proceeds exceeded the then
carrying value of the Company's investment in the Russian projects and the
resulting gain of $12,222,000 was included in income. Until June 30, 1999, the
date of loss of control, the Company proportionately consolidated Russian
operations.

46

10. INCOME TAXES

The Company and its subsidiaries are required to individually file tax returns
in each of the jurisdictions in which they operate. Details of the determination
of the actual income tax expense for each of the three years are detailed below.
For ease of presentation, the loss, as a result of the write down of Russian
assets, and the subsequent gain on settlement has been classified as Russian
operations, even though neither of these two items have any tax effect in
Russia. The actual loss of approximately $35 million, being the aggregate
investment, ignoring accounting write downs, less proceeds received on
settlement will be a capital loss for Canadian income tax purposes, available
for carry-forward against future Canadian capital gains indefinitely.

The tax loss carry-forwards in Canada are Cdn. $39,394,000 and in the United
States $40,752,000. The tax losses carry-forward in Canada expire between 2003
and 2008, in the United States between 2018 and 2021. In China the Company has
available for carry-forward against future Chinese income $37,193,000 of cost
basis. In addition, the carrying value of assets for accounting purposes is
$28,861,000 greater than that available for tax purposes. Due to the uncertainty
of utilizing these net tax assets, the Company has made a valuation allowance of
an equal amount against these potential recoverable amounts as detailed below.

11. NET INCOME (LOSS) PER SHARE

The Company has adopted retroactively the treasury method to assess the
potential impact of outstanding stock options, convertible debentures and share
purchase warrants on earnings per share, as promulgated by Canadian GAAP. The
treasury stock method conforms to the practice followed in the United States.

This change has resulted in a change to reported diluted net income per share
for the year ended December 31, 2000 to $0.04 from $0.05 as previously reported.
The number of shares used to calculate diluted earnings per share for the year
ended December 31, 2000 of 124,549,000 included the weighted average number of
shares outstanding of 119,719,000 plus 4,802,000 shares related to the dilutive
effect of stock options and 28,000 shares related to share purchase warrants.
For the year ended December 31, 2001, if the diluted calculation were performed
for other than net loss, the number of shares which would have been used of
132,616,000 would have included the weighted average number of shares
outstanding of 128,598,000 plus 4,018,000 shares related to the dilutive effect
of stock options.

The diluted earnings per share computations discussed above did not include
240,000 (2000 -- 724,000) of share options and 2,500,000 (2000 -- 514,000) of
share purchase warrants, both on a weighted

47

average basis, because the respective exercise prices exceeded the average
market price of the common shares. Similarly, the number of shares, which would
be issued on conversion of the convertible debenture, are not included as the
effect would be anti-dilutive for 2001 and 2000.

12. RELATED PARTY TRANSACTIONS

The Company has entered into agreements with a number of entities, some of which
are related through common directors or shareholders, to share administrative
personnel, office space, and facilities. The Company is billed on a cost
recovery basis. The costs incurred in the normal course of business with respect
to the above arrangements amounted to $2,650,000 for 2001, $1,581,000 for 2000,
and $1,692,000 for 1999. In addition, a company controlled by a director
provides consulting services to the Company. During the year $673,000 was paid
for such consulting services and out of pocket expenses. At year end amounts
included in accounts payable under these arrangements totaled $1,148,000 in 2001
and $486,000 in 2000.

13. SUBSEQUENT EVENT

Effective January 22, 2002 the Company finalized the sale of its Daqing project
to an unrelated party for $2,400,000: $1,200,000 cash on closing and a
$1,200,000 non-interest bearing promissory note receivable due on or before
September 1, 2002. The Company also retains an overriding royalty of 4% before
cost recovery and 2% thereafter. The sale proceeds will be credited to the full
cost pool, (Note 2) as the sale does not represent a significant disposition of
the China total reserve base.

14. COMPARATIVE FIGURES

Certain of the comparative amounts have been reclassified to conform to the
presentation adopted for the current year.

15. ADDITIONAL DISCLOSURES REQUIRED UNDER UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES ("GAAP")

The Company's consolidated financial statements have been prepared in accordance
with GAAP as applied in Canada. In the case of the Company, Canadian GAAP
conforms in all material respects with United States GAAP, except for certain
matters, which were mentioned in Note 2. Where these matters impact the
financial statements, the details of the differences are as follows:

CONSOLIDATED STATEMENTS OF LOSS (INCOME)

As discussed under Oil and Gas Properties in this note, there is a difference in
performing the ceiling test evaluation under full cost accounting between United
States and Canadian GAAP. Application of the ceiling test evaluation under
United States GAAP requires an additional $10,000,000 provision for impairment
with respect to the Company's China properties.

In addition, the capitalization of development costs permitted under Canadian
GAAP in connection with our GTL prospects is not permitted under United States
GAAP.

The Company, in connection with its initial public offering in June 1997, placed
in escrow 31,457,000 common shares held by certain shareholders, to be released
one-third per year on the succeeding three anniversary dates of the public
offering. For Canadian GAAP, as the release of shares from escrow is based on
time rather than on any performance criteria, these shares are considered issued
and outstanding and form part of the calculation of earnings and fully dilutive
earnings per share. Under United States GAAP, these escrow shares are considered
issued and outstanding only after they are released from escrow.

Under United States GAAP, interest income and gain on sale of Russian projects
would be classified as other income.

48

The application of United States GAAP has the following effects on net loss
(income) and net loss (income) per share as reported:

The Company has no items that would be disclosed as other comprehensive income
under United States GAAP.

STOCK BASED COMPENSATION

The Company has a stock-based compensation plan as more fully described in Note
7. With regards to its stock option plan, the Company applies APB Opinion No.
25, as interpreted by FASB ("FIN") 44, in accounting for this plan and
accordingly no compensation cost has been recognized. Had compensation expense
been determined based on fair value at the stock option grant date, consistent
with the method of Statement of Financial Accounting Standards No. 123,
Accounting for Stock-Based Compensation, the Company's net loss (income) and net
loss (income) per share would have been reduced to the pro forma amounts
indicated below:

The foregoing information is calculated in accordance with the Black-Scholes
option pricing model, using the following data and assumptions: volatility, as
of the date of grant, computed using the prior one to three-year weekly average
prices of the Company's common shares, which ranged from 59% to 108%; expected
dividend yield -- 0%; option terms to expiry -- 5 to 10 years as defined by the
option contracts; risk-free rate of return as of the date of grant -- 4.87% to
5.70%, based on five year Government of Canada Bond yields.

49

CONSOLIDATED BALANCE SHEETS

The application of United States GAAP would have the following effects on
balance sheet items as reported:

SHAREHOLDERS' EQUITY

Shareholders' equity at December 31, 2001 under Canadian
GAAP...................................................... $96,897
Adjustment to ascribed value of shares issued for royalty
interests (Note 3)........................................ 1,358
Impairment provision for China properties required under
United States GAAP........................................ (10,000)
Write off of GTL development costs required under United
States GAAP............................................... (5,142)
-------
Shareholders' equity at December 31, 2001 under United
States GAAP............................................... $83,113
=======
Shareholders' equity at December 31, 2000 under Canadian
GAAP...................................................... $95,838
Adjustment to ascribed value of shares issued for royalty
interests (Note 3)........................................ 1,358
-------
Shareholders' equity at December 31, 2000 under United
States GAAP............................................... $97,196
=======

Under United States GAAP, the transfer of deficit to share capital, which
occurred during the year ended December 31, 1999, would not be recognized (Note
5). As a result, shareholders' equity under United States GAAP would comprise
the following:

OIL AND GAS PROPERTIES

There are certain differences between the full cost method of accounting for oil
and gas assets as applied in Canada and as applied in the United States. The
principal difference results in the method of performing ceiling test
evaluations under the full cost accounting rules. Under Canadian GAAP, non-
discounted future net revenues from oil and gas production, less an estimate for
future general and administrative expenses, financing costs and income taxes are
compared to the carrying value of the depletable petroleum properties, whereas
for United States GAAP future net revenues are discounted to present value at
10% per annum and compared to the carrying value of the depletable petroleum
properties. The Company has performed the ceiling test in accordance with US
GAAP and determined that there would be an additional provision for impairment
required in connection with the Company's China properties of $10,000,000. No
material variances in financial statement balances would have resulted in 2000
or 1999.

50

The categories of costs included in the cost of oil and gas properties,
equipment and GTL investments, including the adjustments in accordance with U.S.
GAAP, to the ascribed value of shares issued for royalty interests of $1,358,000
(Note 3), an additional provision for impairment of $10,000,000 and the write
off of GTL development costs are as follows:

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following is the breakdown of accounts payable and accrued liabilities:

CONSOLIDATED STATEMENTS OF CASH FLOW

As a result of the write off of GTL development costs required under United
States GAAP the statement of cash flow as reported would change as follows: cash
flow from operating activities would change from a cash flow of $2,433,000 to a
cash flow deficiency of $2,709,000, and oil and gas properties, equipment and
GTL investments reported under investing activities of $40,504,000 would change
to $35,362,000.

IMPACT OF NEW AND PENDING UNITED STATES GAAP ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board ("FASB") approved SFAS
No. 141, "Business Combinations" and issued this statement in July 2001. SFAS
No. 141 establishes new standards for accounting and reporting requirements for
business combinations and will require that the purchase method of accounting be
used for all business combinations initiated after June 30, 2001. Use of the
pooling of interest method will be prohibited. Management does not believe that
SFAS No.141 will have a material impact on the Company's financial statements.

In June 2001, the FASB approved SFAS No. 142 "Goodwill and Other Intangible
Assets", which supercedes APB Opinion No. 17, "Intangible Assets". The FASB
issued this statement in July 2001. SFAS No.142 establishes new standards for
goodwill acquired in a business combination and eliminates amortization of
goodwill and instead sets forth methods to periodically evaluate goodwill for
impairment. Management does not believe that SFAS No.142 will have a material
impact on the Company's financial statements.

51

In June 2001, the FASB approved SFAS No. 143, "Accounting for Asset Retirement
Obligations", which addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. SFAS No.143 is effective for fiscal years beginning
after June 15, 2002.. Management does not believe that SFAS No.143 will have a
material impact on the Company's financial statements.

In October 2001 the FASB issued SFAS No.144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", resolving significant implementation issues
related to FASB Statement No.121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of", and supercedes the
accounting and reporting provisions of APB Opinion No.30, "Reporting the Results
of Operations-Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions", for
the disposal of a business segment. SFAS No.144 is effective for the fiscal
years beginning after December 15, 2001 and interim periods within those fiscal
years. Management does not believe that SFAS No.144 will have a material impact
on the Company's financial statements.

SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES
(UNAUDITED)

The following information about the Company's oil and gas producing activities
is presented in accordance with United States Statement of Financial Accounting
Standards No. 69: Disclosures About Oil and Gas Producing Activities.

OIL AND GAS RESERVES

Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic conditions.

Proved developed oil and gas reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

Estimates of oil and gas reserves are subject to uncertainty and will change as
additional information regarding the producing fields and technology becomes
available and as future economic conditions change.

Reserves presented in this section represent the Company's working interest
share of reserves net of royalties. The reserves for 2001 and 2000 in the U.S.
are based on estimates by the independent petroleum engineering firm of Joe C.
Neal & Associates and Allan Spivak Engineering. In China, the reserves are based
on estimates by the independent petroleum engineering firm of Gilbert Laustsen
Jung Associates Ltd.

Our Daqing project in China was sold subsequent to year end. For purposes of the
schedules detailed below the total reserves for Daqing of 3,449 MBbls at
December 31, 2001 are included and valued at the consideration to be received in
2002.

52

The Company's net proved and net proved developed oil and gas reserves are as
follows:

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES

The following standardized measure of discounted future net cash flows from
proved oil and gas reserves has been computed using period end prices of $15.37
per barrel of oil ($23.95 per barrel in 2000 and $22.95 per barrel in 1999) and
$2.76 per Mcf of gas ($5.65 per mcf in 2000) and costs and period end statutory
tax rates. A discount rate of 10% has been applied in determining the
standardized measure of discounted future net cash flows.

The Company does not believe that this information reflects the fair market
value of its oil and gas properties. Actual future net cash flows will differ
from the presented estimated future net cash flows in that:

- future production from proved reserves will differ from estimated
production;
- future production will also include production from probable and
potential reserves;
- future rather than year end prices and costs will apply; and
- existing economic, operating and regulatory conditions are subject to
change.

The standardized measure of discounted future net cash flows as at December 31
in each of the three most recently completed financial years are as follows:

53

Changes in standardized measure of discounted future net cash flows as at
December 31 in each of the three most recently completed financial years are as
follows:

COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION, DEVELOPMENT AND
GTL ACTIVITIES FOR THE FOLLOWING PERIODS ENDED:

Depletion, per unit of net production, before provision for impairment:

54

RESULTS OF PRODUCING ACTIVITIES:

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

55

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides the names of all of our directors and executive
officers, their positions, terms of office and their principal occupations
during the past five years. Each director is elected for a one year term or
until his successor has been duly elected or appointed. Officers serve at the
pleasure of the Board of Directors.

57

Listed below are those of our directors who hold directorships in other publicly
listed corporations and the names of those corporations:

ROBERT M. FRIEDLAND: Ivanhoe Mines Ltd.
R. EDWARD FLOOD: Diamond Fields International Ltd., Emperor Mines Limited,
Ivanhoe Mines Ltd.
Olympus Pacific Minerals Inc.
HOWARD R. BALLOCH: Zi Corporation

Each of our directors, with the exception of Mr. Howard Balloch who was
appointed to the Board in January, 2002, was elected at our last annual general
meeting of shareholders. The term of office of each director concludes at our
next annual general meeting of shareholders, unless the director's office is
earlier vacated in accordance with our by-laws. There are no family
relationships among any of our directors, officers or key employees.

As required under the Business Corporations Act (Yukon), our Board of Directors
has an Audit Committee. We also have a Compensation and Benefits Committee. The
members of the Audit Committee are Messrs. Edward Flood, Howard Balloch and
Shun-Ichi Shimizu The members of the Compensation and Benefits Committee are
Messrs. David Martin and Edward Flood.

Management is responsible for our financial reporting process including our
system of internal control and for the preparation of consolidated financial
statements in accordance with generally accepted accounting principles in
Canada. Our independent auditors are responsible for auditing those financial
statements. The members of the audit committee are not our employees, and are
not professional accountants or auditors. The audit committee's primary purpose
is to assist the Board of Directors to fulfill its oversight responsibilities by
reviewing the financial information provided to shareholders and others, the
systems of internal controls which management has established to preserve our
assets and the audit process. It is not the audit committee's duty or
responsibility to conduct auditing or accounting reviews or procedures or to
determine that our financial statements are complete and accurate and in
accordance with generally accepted accounting principles in Canada. In giving
its recommendation to the Board of Directors, the audit committee has relied on
management's representations that the financial statements have been prepared
with integrity and objectivity and in conformity with generally accepted
accounting principles in Canada and on the representations of the independent
auditors included in their report on our financial statements.

Based solely on a review of the reports furnished to us, we believe that during
2001 all of our directors, executive officers and 10% shareholders complied with
the applicable requirements for reporting initial ownership and changes in
ownership of our common shares.

ITEM 11. EXECUTIVE COMPENSATION

During the fiscal year ended December 31, 2001 we paid our executive officers
$804,955 aggregate cash compensation. In 2001 the Company adopted a defined
contribution retirement or thrift plan (401(k) Plan) to assist U.S. employees in
providing for retirement or other future financial needs. Employees
contributions (up to the maximum allowed by U.S. tax laws) are matched by the
Company 50% in 2001 and increasing 10% per year thereafter to a maximum of a
100%.

The following executive compensation disclosure relates to our President and
Chief Executive Officer as at December 31, 2001, and each of our four most
highly compensated executive officers (collectively, the "named executive
officers") whose annual compensation exceeded $100,000 in the year ended
December 31, 2001. During the year ended December 31, 2001, the total
compensation paid to those of our officers who received more than $100,000 in
total compensation was $804,955.

58

SUMMARY COMPENSATION

We paid the following compensation during the years ending December 31, 1999,
2000 and 2001 to each of our named executive officers.

SUMMARY COMPENSATION TABLE

(1) Mr. E. Leon Daniel was appointed as our President and Chief Executive
Officer on June 22, 1999, and has been one of our directors since August
25, 1998.

(2) Mr. Chua was appointed as an Executive Vice-President in June, 1999.

(3) Mr. O'Keefe has been Executive Vice President Investor Relations and Chief
Financial Officer since September, 2000.

(4) Mr. Martin has been our Chairman and one of our directors since August,
1998.

(5) Mr. Moench was appointed an Executive Vice-President in June, 1999.

(6) Includes premiums paid by us on behalf of the named executive officer for
medical, dental and other health insurance coverage.

59

OPTIONS AND STOCK APPRECIATION RIGHTS (SARS)

We granted the following Options/SARS to our named executive officers in the
financial year ended December 31, 2001:

OPTION/SAR GRANTS IN LAST FISCAL YEAR

(1) Equal to or greater than the weighted average price of our common shares on
The Toronto Stock Exchange for the five trading days preceding the date of
a grant.

AGGREGATED OPTION EXERCISES

The aggregate number of options exercised by any of the named executive officers
during the financial year ended December 31, 2001 was 5,000.

AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND
FINANCIAL YEAR END OPTION/SAR VALUES

PENSION PLANS

We do not presently provide a pension plan for our employees however, in 2001
the Company adopted a defined contribution retirement or thrift plan (401(k)
Plan) to assist US employees in providing for retirement or other future
financial needs. Employees contributions (up to the maximum allowed by US tax
laws) are matched by the Company 50% in 2001 and increasing 10% per year
thereafter to a maximum of a 100%. The Company's contributions to the 401(k)
Plan in 2001 was $78,000.

EMPLOYMENT CONTRACTS, TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS

We have no written employment contracts or termination of employment or change
of control arrangement with any of our directors or named executive officers
except for John O'Keefe, whose employment contract provides for one year's
severance, without cause, and on termination the immediate vesting of all
outstanding options.

60

DIRECTOR AND NAMED EXECUTIVE OFFICER COMPENSATION

We did not pay cash or other fixed compensation to our directors. Effective
January 1, 2002 all independent directors will receive director fees of $2,000
per month. We reimburse our directors for expenses they reasonably incur in the
performance of their duties as directors and they are also eligible to receive
stock bonus awards from time to time and to participate in our Employees' and
Directors' Equity Incentive Plan.

The cash compensation we pay to the named executive officers is intended to be
comparable to the cash compensation paid to executive officers of similar
companies who have comparable duties and responsibilities.

EMPLOYEES' AND DIRECTORS' EQUITY INCENTIVE PLAN

Our Employees' and Directors' Equity Incentive Plan, as amended (the "Plan")
consists of three component plans: a common share option plan (the "Share Option
Plan"), a common share bonus plan (the "Share Bonus Plan"), and a common share
purchase plan (the "Share Purchase Plan"). The purpose of the Plan is to advance
our corporate interests, by encouraging equity participation by our directors,
officers, employees and service providers through the acquisition of our shares.

The following is a brief description of the terms of the Plan.

SHARE OPTION PLAN

The Share Option Plan allows the board of directors to grant options to acquire
our common shares in favour of our directors, officers, employees and service
providers. Options are subject to adjustment in the event of a subdivision or
consolidation of our common shares, an amalgamation, or other corporate event
affecting our common shares. Participation in the Share Option Plan is limited
to directors, officers, employees and service providers, who are, in the opinion
of our board of directors, in a position to contribute to our future growth and
success.

In determining the number or value of optioned common shares made subject to
options, we consider the optionee's present and potential contribution to our
success and to the prevailing policies of each stock exchange on which our
shares are listed. The board of directors determines the date of grant, the
number of shares, the exercise price per share, the vesting period, and all
other terms and conditions of the options we grant. The minimum exercise price
of any option granted under the Share Option Plan is the weighted average price
of our common shares on the principal stock exchange on which our common shares
trade for the five trading days prior to the date of grant.

Unless earlier terminated upon an optionee's death or termination of employment
or appointment, options are exercisable for a period of up to ten years. We may,
in our discretion, accelerate unvested options if a take-over bid is made for
our common shares.

We may also grant share appreciation rights when we grant an option. Such rights
permit an optionee to elect to terminate the option and instead receive common
shares on the basis of a cashless exercise. The number of common shares that an
optionee who exercises share appreciation rights will receive is equal to the
difference between the then fair market value per common share and the option
price per common share of all common shares under option, divided by the then
fair market value per common share.

SHARE BONUS PLAN

The Share Bonus Plan permits our board of directors to issue a maximum of
1,000,000 of our common shares as bonus awards to our directors, employees and
service providers on a discretionary basis having regard to such merit criteria
as the board of directors may determine.

61

SHARE PURCHASE PLAN

Participation in the Share Purchase Plan is limited to employees who have
completed at least one year (or less, at the discretion of the board of
directors) of continuous service on a full-time basis and who are designated by
the board of directors as eligible to participate in the Share Purchase Plan.

Eligible employees may contribute up to 10% of their annual basic salary to the
Share Purchase Plan in semi-monthly installments. We then make contributions on
a quarterly basis equal to the employee's contribution.

At the end of each calendar quarter, the eligible employee receives a number of
our common shares equal to the aggregate amount contributed by the employee
participant and by us, on the participant's behalf, divided by the weighted
average trading price of our common shares on our principal stock exchange
during the previous three months.

The Share Purchase Plan component of the Plan has not yet been activated.

GENERAL

The aggregate maximum number of our common shares which we may issue or reserve
for issuance under the Plan is currently 15,000,000 common shares. Any increase
is subject to Toronto Stock Exchange approval and approval by our shareholders.
The maximum number of our common shares which we may, at any time, reserve for
issuance to any one person under the Plan may not exceed 5% of our issued and
outstanding common shares.

Our board of directors has the right to amend, modify or terminate our Equity
Incentive Plan. However, any amendment to the Equity Incentive Plan which would
materially increase the benefits under the Plan, materially modify the
requirements as to eligibility for participation in the Plan or materially
change the number of our common shares that may be issued or reserved for
issuance under the Plan, is subject to Toronto Stock Exchange approval and the
approval of our shareholders.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

During the year ended December 31, 2001, our Compensation and Benefits Committee
consisted of Messrs. Robert Friedland, Edward Flood and David Martin. Mr. Martin
is one of our executive officers. Mr. Friedland is our largest shareholder and
holds interests in other entities with which we have transacted, and continue to
transact, business. See Item 13. "Certain Relationships and Related
Transactions." Mr. Friedland resigned his position on the Compensation and
Benefits Committee in the second half of the year ended December 31, 2001.

BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION

The Compensation and Benefits Committee administers our executive compensation
program, which is designed to provide incentives for our executive officers to
enhance shareholder value. Our principal objectives are to attract and retain
qualified executives critical to our success, to provide fair and competitive
compensation, to align their interests with those of our shareholders, and to
reward extraordinary corporate and individual performance on an annual basis. We
structure each compensation package in a manner that we believe links
shareholder return, measured by appreciation in share price, with executive
compensation. Stock options are the primary mechanism we use to align management
and shareholder interests. We do not offer pension plans to our senior
executives.

Submitted on behalf of the Compensation Committee:

Mr. Edward Flood
Mr. David Martin

62

PERFORMANCE GRAPH

The following graph and table compares the cumulative shareholder return on a
$100 investment in common shares of the Company to a similar investment in
companies comprising the TSE 300 Total Return Index, including dividend
reinvestment, for the period from December 31, 1997 to December 31, 2001.

(Performance)

63

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Except as set forth below, no person or group is known to beneficially own (as
deemed by SEC Regulations) 5% or more of our issued and outstanding common
shares. Based on information known to us, the following table sets forth the
beneficial ownership of each such person or group in our common shares at March
1, 2002.

- ---------------

(1) Beneficial ownership is determined in accordance with the rules of the
Securities and Exchange Commission and generally includes voting or
investment power with respect to securities. Unissued common shares subject
to options, warrants or other convertible securities currently exercisable
or convertible, or exercisable or convertible within 60 days, are deemed
outstanding for the purpose of computing the beneficial ownership of common
shares of the person holding such convertible security but are not deemed
outstanding for computing the beneficial ownership of common shares of any
other person.

(2) 46,194,620 outstanding common shares are held indirectly through Newstar
Securities Ltd., Premier Mines Limited and Evershine LLC, companies
controlled by Mr. Friedland.

(3) Includes 2,500,000 common shares issuable upon exercise of share purchase
warrants.

(4) Includes 3,024,733 common shares issuable upon the exercise of incentive
stock options held by directors and executive officers as a group.

64

SECURITY OWNERSHIP OF MANAGEMENT

The following table sets forth the beneficial ownership at March 1, 2002 of our
common shares by each of our directors, our named executive officers and by all
of our directors and executive officers as a group:

- ---------------

(1) Includes unissued common shares issuable upon the exercise of incentive
stock options.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

TRANSACTIONS WITH MANAGEMENT AND OTHERS

Not applicable.

CERTAIN BUSINESS RELATIONSHIPS

We are parties to cost sharing agreements with other companies in which Mr.
Robert M. Friedland has a material direct or indirect beneficial interest.
Through these agreements, we share office space, furnishings, equipment and
communications facilities in Vancouver, Singapore and London and an aircraft on
a cost recovery basis. We also share the costs of employing administrative and
non-executive management personnel at these offices. During the year ended
December 31, 2001, our share of these costs was $2,650,000. The companies, with
which we are parties to the cost sharing agreements, and Mr. Friedland's
ownership interest in each of them, are as follows:

A company controlled by a director, and a director receive fees for providing
consulting services. During the year ended December 31, 2001 a company
controlled by Mr. Shun-ichi Shimizu received $673,000 for consulting services
and out of pocket expenses. Mr. John Carver receives $30,000 per quarter for
services provided.

65

TABLE OF INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS
AND SENIOR OFFICERS

We loaned Messrs. Martin and Flood Cdn. $200,000 and Cdn. $60,000 respectively
in January, 2001 to facilitate their exercise of warrants to purchase 50,000 and
15,000 of our common shares respectively. The loans bear interest at the Bank of
Montreal prime rate as quoted from time to time and the loans were to mature on
January 26, 2002. By a Directors resolution of January 9, 2002 the loans were
renewed under the same terms and conditions and now mature on January 26, 2003.
The loans are secured by a pledge of the 50,000 common shares owned by Mr.
Martin and the 15,000 common shares owned by Mr. Flood.

66

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

The following financial statements and exhibits are filed as part of this Annual
Report:

(a) 1. FINANCIAL STATEMENTS:

Deloitte & Touche, LLP Auditors' Report on Consolidated Balance
Sheets of Ivanhoe Energy Inc. as at December 31, 2001 and 2000 and
Consolidated Statements of Loss and Deficit and Consolidated
Statements of Cash Flow of Ivanhoe Energy Inc. for the years ended
December 31, 2001, 2000 and 1999.

Consolidated Balance Sheets of Ivanhoe Energy Inc. as at December
31, 2001 and 2000.

Consolidated Statements of Loss and Deficit of Ivanhoe Energy Inc.
for the years ended December 31, 2001, 2000 and 1999.

Consolidated Statements of Cash Flow of Ivanhoe Energy Inc. for the
years ended December 31, 2001, 2000 and 1999.

Notes to the Consolidated Financial Statements of Ivanhoe Energy
Inc. for the years ended December 31, 2001, 2000 and 1999.

2. FINANCIAL STATEMENT SCHEDULES:

Supplementary Disclosures about Oil and Gas Production Activities
(Unaudited)

3. EXHIBITS

3.1 Articles of Ivanhoe Energy Inc. as amended to June 24, 1999
(incorporated by reference to Exhibits 1.1 through to 1.4 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).

3.2 Bylaws of Ivanhoe Energy Inc. (incorporated by reference to
Exhibit 1.1 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).

4.1 Amended and Restated Convertible Loan Agreement dated August
4, 1999 between Ivanhoe Energy Inc. and Linyi Holdings Ltd.
(incorporated by reference to Exhibit 3.2 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).

10.1 Funding and Participation Agreement dated August 1, 1998
between Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.) and Diatom Petroleum, Incorporated
(incorporated by reference to Exhibit 3.3 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).

10.2 Exploration Agreement dated May 1, 1998 between Diatom
Petroleum, Incorporated and Aera Energy LLC, as amended
January 18, 1999, March 29, 1999, September 15, 1999,
September 21, 1999 and April 5, 2000 (incorporated by
reference to Exhibit 3.4 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000).

10.3 Participation Agreement dated August 1, 1996 between Aera
Energy LLC (formerly CalResources, LLC), Digital
Petrophysics, Inc., Ivanhoe Energy (USA) Inc. (formerly West
Best Resources Ltd.) (as assignee of Texaco Exploration and
Production Inc.) and Wood Oil Company, as amended December
11, 1998 and further amended October 13, 1999 (incorporated
by reference to Exhibit 3.5 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000).

67

10.4 Participation Agreement dated February 15, 1999 between Aera
Energy LLC, Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.), Diatom Petroleum, Inc. and Armstrong
Resources, LLC, as amended September 9, 1999 and further
amended November 15, 1999 (incorporated by reference to
Exhibit 3.9 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).

10.5 Petroleum Contract for Kongnan Block, Dagang Oilfield of the
People's Republic of China dated September 8, 1997 between
China National Petroleum Corporation and Pan-China Resources
Ltd., as amended June 11, 1999 (incorporated by reference to
Exhibit 3.15 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).

10.6 Exploration Agreement dated October 1, 1999 between Prime
Natural Resources, LLC, Ivanhoe Energy (USA) Inc. and Aera
Energy LLC (incorporated by reference to Exhibit 3.23 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).

10.7 Service Agreement dated September 1, 1999 of CUE Management
Consultants Limited (incorporated by reference to Exhibit
3.31 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000).

10.8 Volume License Agreement dated April 26, 2000 between
Syntroleum Corporation and Ivanhoe Energy Inc. (incorporated
by reference to Exhibit 3.37 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000).

10.9 Agreement dated May 11, 2000 between Discovery Operating,
Inc., Don L. Sparks and Ivanhoe Energy (USA) Inc.
(incorporated by reference to Exhibit 3.38 of Amendment No.
2 to Form 20-F filed with the Securities and Exchange
Commission on July 24, 2000).

10.10 Consultancy Agreement dated June 2, 2000 between Ivanhoe
Energy Inc. and M&A Oil Consultancy Limited (incorporated by
reference to Exhibit 3.39 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000).

10.11 Master License Agreement Amendment No. 1 dated October 11,
2000 between Syntroleum Corporation and Ivanhoe Energy Inc.
(incorporated by reference to Exhibit 10.18 of Form 10-K
filed with the Securities and Exchange Commission on March
16, 2001).

10.12 Consulting Agreement dated November 15, 2000 between Ivanhoe
Energy Inc. and Continental Energy Limited (incorporated by
reference to Exhibit 10.19 of Form 10-K filed with the
Securities and Exchange Commission on March 16, 2001).

10.13 Employees' and Directors' Equity Incentive Plan
(incorporated by reference to Exhibit 10.20 of Form 10-K
filed with the Securities and Exchange Commission on March
16, 2001).

10.14 Agreement for the Sale and Purchase of Shares in Great
Plains Petroleum (Cyprus) Limited and Global Petroleum
(Cyprus) Limited dated August 10, 2000 between Kuban
Petroleum Ltd., Ivanhoe Energy Inc. and Stesana Enterprises
Limited (incorporated by reference to Exhibit 10.21 of Form
10-K filed with the Securities and Exchange Commission on
March 16, 2001).

10.15 Deed of Release dated August 10, 2000 between Ivanhoe Energy
Inc., Kuban Petroleum Ltd., Tyumen Oil Company and
Tyumeneftegaz (incorporated by reference to Exhibit 10.22 of
Form 10-K filed with the Securities and Exchange Commission
on March 16, 2001).

10.16 Agreement to Purchase shares of Digital Petrophysics, Inc.
dated January 26, 2001 between Ivanhoe Energy (USA) Inc.,
William R. Berry II and Deborah M. Olsen (incorporated by
reference to Exhibit 10.23 of Form 10-K filed with the
Securities and Exchange Commission on March 16, 2001).

68

10.17 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Zitongxi and Zitongdong
Blocks (incorporated by reference to Exhibit 10.24 of Form
10-K filed with the Securities and Exchange Commission on
March 16, 2001).

10.18 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Yudong Block
(incorporated by reference to Exhibit 10.25 of Form 10-K
filed with the Securities and Exchange Commission on March
16, 2001).

10.19 Agreement and Operating Agreement dated 5 March 2001 between
Discovery Operating, Inc., Don L. Sparks, W. Jeffrey Sparks,
Kevin D. Sparks, C. Todd Sparks and Ivanhoe Energy (USA)
Inc. with respect to oil and gas interests in Midland and
Upton County, Texas.

10.20 Participation Agreement dated 10 March 2001 between Hay
Exploration, Inc. and Ivanhoe Energy (USA) Inc. with respect
to oil and gas properties in Elliott, Morgan and Carter
Counties, Kentucky.

10.21 Joint Study Agreement between Petro China Company Limited
and Sunwing Energy Ltd. dated 29 March 2001, for the
purposes of entering into Production Sharing Contracts on
the Yudong block.

10.22 Joint Study Agreement between Petro China Company Limited
and Sunwing Energy Ltd. dated 29 March 2001, for the
purposes of entering into Production Sharing Contracts on
the Zitongxi and Zitondong blocks.

10.23 Joint Venture Agreement and Operating Agreement dated 1 July
2001 between Union Oil Company of California and Ivanhoe
Energy (USA) Inc. on the Cresslen Ranch Area, Henderson
County, Texas.

10.24 Joint Venture Agreement and Operating Agreement dated 1
October 2001 between Union Oil Company of California and
Ivanhoe Energy (USA) Inc., in the Bossier Trend, Anderson,
Freestone & Henderson Counties, Texas.

10.25 Modification Agreement for Petroleum Development Contract
for Kongnan Block, Dagang Oilfield, the People's Republic of
China, dated 24 October 2001.

10.26 Amendment of Petroleum Contract for Petroleum Development
and Production in Zhou 13 Block, Daqing Zhaozhou Oilfield,
of the People's Republic of China dated 28 December 2001.

10.27 Consulting Agreement dated 13 January 2002 between Ivanhoe
Energy Inc. and Nahwan Trading LLC.

21.1 Subsidiaries of Ivanhoe Energy Inc.

23.1 Consent of Gilbert Laustsen Jung Associates Ltd., Petroleum
Engineers.

23.2 Consent of Allan Spivak Engineering.

23.3 Consent of Joe C. Neal & Associates.

(b) REPORTS ON FORM 8-K:

None.

69

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.

IVANHOE ENERGY INC.

By: /s/ E. LEON DANIEL
--------------------------------------
Name: E. Leon Daniel
Title: President and Chief Executive
Officer
Dated: March 14, 2002

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 dates indicated.

70

EXHIBIT INDEX

(B) REPORTS ON FORM 8-K:

None.