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.