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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, 2000.
or
[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
For the transition period from ___________ to ___________.
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.)
9TH FLOOR - WATERFRONT CENTRE
200 BURRARD STREET
VANCOUVER, BRITISH COLUMBIA, CANADA
V6C 3L6
(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
--------------------------- -----------------------------------------
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, 2001 based on the closing price on the NASDAQ National
Market on that date, was $373,264,526.
Documents incorporated by reference: None
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TABLE OF CONTENTS
PAGE
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PART I
Items 1 and 2. Business and Properties..................................... 4
Corporate Overview.......................................... 4
Overview of the Business.................................... 4
Corporate Strategy.......................................... 5
Gas-to-Liquids Projects..................................... 6
Oil and Gas Properties...................................... 7
Competition................................................. 12
Environmental Regulations................................... 12
Government Regulations...................................... 12
Employees................................................... 13
Reserves, Production and Related Information................ 13
Item 3. Legal Proceedings........................................... 15
Item 4. Submission of Matters to a Vote of Security Holders......... 16
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 16
Item 6. Selected Financial Data..................................... 18
Item 7. Management's Discussion and Analysis of Financial Condition
and
Results of Operations....................................... 19
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 29
Item 8. Financial Statements and Supplementary Data................. 31
Item 9. Changes In and Disagreements with Accountants on Accounting
and
Financial Disclosure........................................ 58
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 58
Item 11. Executive Compensation...................................... 60
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 65
Item 13. Certain Relationships and Related Transactions.............. 66
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 69
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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, 2000 as reported by the Federal Reserve Bank of New
York were as follows:
2000 1999 1998 1997
------- ------- ------- -------
Closing............................................ $0.6669 $0.6925 $0.6504 $0.6999
Low................................................ 0.6410 0.6441 0.6341 0.6945
High............................................... 0.6969 0.6925 0.7105 0.7487
Average Noon....................................... 0.6730 0.6730 0.6714 0.7198
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,
2001 was $0.6466 ($1.00 = Cdn.$1.5465). 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
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 and our
negligible revenue since we lost control of our principal Russian project;
losses and negative cash flow from our current exploration and development
operations in California, Texas 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 California,
Texas 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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ITEMS 1 AND 2. BUSINESS AND PROPERTIES
CORPORATE OVERVIEW
We are an international energy company engaged in conventional oil and gas
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.
Our principal executive offices are located at 900 - 200 Burrard Street,
Vancouver, British Columbia, V6C 3L6, 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.
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 and California. In
1999, we acquired property interests in China. In April, 2000 we acquired a
limited volume license from Syntroleum Corporation ("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. Finally, in May, 2000, we began acquiring interests in oil
and gas exploration properties in Texas.
In Peru, we earned a 50% participating interest in an exploration and
development concession in the Ucayali Basin by funding drilling expenditures of
approximately $13.5 million. The initial exploratory well was dry and we
subsequently plugged and abandoned it. At this time we have no plans to continue
exploration or development in Peru and we have relinquished our interest in the
concession.
In Russia, a dispute with our joint venture partner prevented us from proceeding
with our operations in the area. In the summer of 2000, we settled the dispute
and sold our interest in our Russian properties. See Item 3. "Legal
Proceedings".
In California, we have been accumulating working interests and royalty interests
in the San Joaquin Valley since 1998. Our key asset in California is an
exploration agreement with Aera Energy LLC ("Aera"), a company owned by two
major integrated petroleum companies, which entitles 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
Properties".
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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 now have two production sharing
contracts with China National Petroleum Corporation ("CNPC") which entitle us to
develop and operate the Kongnan oilfield in Dagang, located in Hebei Province
and the Zhaozhou oilfield in Daqing, located in Heilongjiang Province. Nippon
Oil Exploration Limited ("Nippon") of Japan is participating with us in the
development of the Kongnan oilfield and holds a 20% working interest. See "Oil
and Gas Properties -- China Properties".
In February, 2001, we entered into two memoranda of understanding with
PetroChina Corporation Limited, a subsidiary of CNPC. These memoranda give 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. to
earn a 62.5% working interest (reducing to 50% after cost recovery) in over
9,100 gross acres of oil and gas exploration property in the Spraberry Trend of
the West Texas Permian Basin in Midland County, Texas. We have also recently
acquired a working interest in over 28,400 gross acres in the Bossier gas sands
in East Texas. See "Oil and Gas Properties -- Texas Properties".
We are also pursuing various opportunities to develop GTL projects using
proprietary technology we licensed from Syntroleum. During 2000, we obtained a
master license from Syntroleum to use its 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 have also agreed in principle to become a partner in Syntroleum's Sweetwater
GTL project in Western Australia. Subject to certain conditions, including
Syntroleum's obligation to arrange project financing, we will invest $21 million
to purchase a 13% equity interest 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 recently completed pilot-test program. Our Daqing project
is also in production under the operatorship of CNPC. We will resume
operatorship once we begin to implement our recently approved development plan.
We continue to examine opportunities to expand our production.
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. Over the
past two years, we have accumulated substantial acreage in the San Joaquin
Basin. We recently completed 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. We plan to begin drilling our first deep gas exploration well
in the Northeast Lost Hills area of the San Joaquin Basin with our partner,
Aera, in the second quarter of 2001. In the fourth quarter of
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2000, we purchased a working interest in over 28,400 gross acres of the Bossier
sands of East Texas where we plan to drill gas targets in the third quarter of
2001.
We also continue to pursue our enhanced oil recovery initiatives in China. We
are encouraged by the results achieved in our pilot programs at Dagang and
Daqing and plan to proceed with the development phase of each project. The
Chinese government approved our development plan for Daqing and we plan to
submit our Dagang development plan to the government for approval in the third
quarter of 2001. We also plan to seek 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 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 a number of opportunities in the Middle East and elsewhere 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
In April, 2000, we acquired a non-exclusive volume 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) subject to an
aggregate limit of 50,000 barrels per day of synthetic GTL products. In October,
2000, we upgraded our volume license to a non-exclusive master license which
entitles us to an unlimited number of GTL projects within the same geographical
areas without any production volume limitations.
SYNTROLEUM PROCESS
Syntroleum's proprietary GTL process is designed to catalytically convert 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 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 gas exists in
known reservoirs which cannot be marketed on
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an economic basis. Operators consider gas to be stranded based on the relative
size of the fields, the location of the gas relative to its market and the cost
to transport the gas to markets.
SWEETWATER GTL PROJECT
In October, 2000, we signed a letter of intent to invest $21 million to
participate as a 13% non-recourse equity partner in Syntroleum's Sweetwater GTL
project under development in Western Australia. We made a $2 million advance
which Syntroleum agreed to use for front-end engineering and other project
development costs. Payment of the balance is subject to a number of conditions,
including fulfilment of Syntroleum's obligation to arrange project financing.
The Sweetwater project is a nominal 10,000 barrels per day plant that will
employ the Syntroleum Process to convert natural gas into ultra-clean synthetic
specialty products such as lubricants, industrial fluids and liquid normal
paraffins, as well as synthetic fuels. The plant will be located on the Burrup
Peninsula in Western Australia and is scheduled for completion in 2003.
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 China. An EOR development which we formerly operated in Russia was
the subject of legal proceedings in the Russian courts and international
arbitration proceedings in Stockholm. We settled these proceedings and sold our
interest in our Russian projects. We held an interest in an exploration property
in Peru but relinquished it during 2000. Set forth below is a description of our
material oil and gas properties.
CALIFORNIA PROPERTIES
Over the past three years, we acquired interests in a number of properties in
the San Joaquin Basin area of California. To date, only our South Midway Sunset
project contains known proved reserves and has wells on production. We cannot
assure you that any of our other projects in California will result in the
development of any producing wells or that production from such wells, if any,
will be commercially viable.
AERA AGREEMENT
In August, 1998, we entered into an agreement with Diatom Petroleum,
Incorporated ("Diatom") whereby we acquired Diatom's rights to explore and earn
working interests in exploration properties in the San Joaquin Valley held by
Aera and others. Diatom's principal asset is an exploration agreement with Aera
(the "Aera Agreement") which entitles Diatom to explore approximately 250,000
acres of Aera and other lands and identify prospects for drilling. In 1999, we
acquired all of the outstanding shares of Diatom.
The lands in which we now hold exploration rights through Diatom are
concentrated in areas adjacent to and under the North and South Belridge, Lost
Hills, Midway Sunset, Coalinga, North and South Coles Levee, Yowlumne and
Belgian Anticline fields. In carrying out our obligations under the Aera
Agreement to identify drillable prospects, we are entitled to use all of the
exploration, seismic and technical data owned by Aera.
Except for those preliminary prospects designated by us and accepted by Aera,
our exclusive rights to explore Aera's properties will expire in September 2001
unless extended by mutual agreement. We will continue to hold exclusive
exploration rights to the lands designated for a period of two years from the
date that Aera accepts our prospect designation. During that time we are
required to focus our activities on identifying drillable prospects within each
preliminary prospect area. If, during this two year period, we identify a
drillable prospect, Aera may elect to retain a working interest in the prospect.
Although the Aera Agreement provides that Aera's working interest will range
from a minimum of 25% to a maximum (depending on the location of the prospect)
of 87.5%, we may negotiate different working interest
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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. Aera must also assign
to Diatom, from all working interests, a 3.5% overriding royalty (the "Diatom
Royalty"). The Diatom Royalty has been subdivided and allocated among various
third parties. See Note 3 to our financial statements under Item 8 in this
Annual Report. Once a drillable prospect is identified, we have two years to
carry out exploration drilling. This two year period will be extended as long as
we continue to drill or have established production.
The properties covered by the Aera 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 thirty leads within 14 preliminary prospect areas
covering approximately 166,000 acres. To date, we have presented six drillable
prospects to Aera for evaluation. Aera has elected to participate in four of the
prospects presented for evaluation. These prospects are the Diamond prospect,
the Northwest Lost Hills #1 prospect, the Amethyst prospect and the Belgian
Anticline prospect. The Belgian Anticline prospect was drilled in December, 2000
and two other leads (Northwest Lost Hills #1 prospect and the Amethyst prospect)
have been scheduled for drilling later in 2001. We have a 100% working interest
in the two prospects in which Aera elected not to participate. One of these
prospects is South Midway Sunset on which we have, to date, drilled 19
successful wells. The other prospect is Citrus, where we expect to drill our
first well during the third quarter of 2001, depending on rig availability.
Set forth below is a description of our material exploration properties which
are subject to the Aera Exploration Agreement.
- - - East Lost Hills/Almond Flank Prospects
In August, 1998, we took an assignment from Texaco Exploration and Production
Inc. of its participating interest in the Almond Flank prospect, a northwestern
extension of the Lost Hills field covering approximately 1,860 acres. We later
acquired, for our own account, approximately 2,000 acres of additional leases in
this area. We currently hold exploration rights to approximately 40% of the
hydrocarbons in this area. The remaining interests are held by Aera and other
parties. Total royalty burdens on the leases do not exceed 23.5%. The leases
through which we hold our interests in the East Lost Hills and Almond Flank
prospects expire between April, 2001 and January, 2005. We are currently
negotiating an extension to the Texaco lease which is scheduled to expire on
April 15, 2001.
We are developing two drillable prospects on our lease position in the
northwestern Lost Hills area. Our first deep-gas exploration well in the San
Joaquin Valley, known as the Ivanhoe Northwest Lost Hills #1, will be drilled in
Kern County. Drilling is expected to commence in the second quarter of 2001.
This prospect is a deep Temblor prospect which lies five miles northwest of, and
on a trend with, the Bellevue No. 1 blowout well, drilled by Berkley Petroleum
Corp. ("Berkley"), which was a Temblor gas discovery. In the 6,300 gross acres
encompassing the Northwest Lost Hills prospect, we hold a maximum working
interest of 47%. Berkley has the right to participate up to 33% in certain
blocks within the acreage including Ivanhoe Northwest Lost Hills #1. If Berkley
exercises this right, our average working interest in the acreage will be
reduced to 42%.
In addition to our Northwest Lost Hills #1 prospect, we are evaluating the
development potential of the Almond Flank prospect, which is a fractured
Monterey play.
- - - Amethyst Prospect (South Belridge)
We have developed the Amethyst prospect in the northern part of the South
Belridge area. We expect to commence drilling in the third quarter of 2001. We
currently have a minimum working interest of 12.5% with Aera holding the
balance.
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- - - Diamond Prospect
We are developing the Diamond prospect in the Lost Hills area. We expect to
complete a 3-D seismic survey over this prospect in the second quarter of 2001.
We currently have a minimum working interest of 12.5% in this prospect, with
Aera holding the balance.
- - - Belgian Anticline Prospect
We identified a drillable prospect on the western flank of the Belgian Anticline
and spudded a well late in 2000. Three potential zones of hydrocarbon bearing
sands totalling 240 gross feet were identified. In December, 2000, it was
determined that two of the three zones were not capable of commercial
production. Testing in the third zone is expected to be completed in the first
half of 2001. We own a 40% working interest in the prospect with Aera holding
the balance.
SOUTH MIDWAY SUNSET PROJECT
We drilled 21 wells in the South Midway Sunset area in 2000. 19 of these wells
are producing oil at commercial rates. We are currently producing approximately
250 barrels per day. We are considering production enhancement options, but have
not yet attempted any such enhancements. The project is primarily designed to
provide immediate cash flow from a low risk, low cost development project with
existing infrastructure. We own a 100% working interest and a 92.9% revenue
interest in the project. Aera elected not to participate in this project but
receives royalties pursuant to the Aera Agreement.
CITRUS PROSPECT
We have applied for a permit to drill a well in the Lost Hills area in 2001.
This project is primarily designed to provide immediate cash flow from a low
risk, low cost development project with existing infrastructure. We own a 100%
working interest in the prospect.
MAGIC MOUNTAIN PROSPECT
We will commence drilling a 12,000 foot well to test our exploration target in
the Ventura basin of Los Angeles County during the first half of 2001. The
prospect contains the same Miocene-Age sands as those of a neighbouring field
that had significant oil and gas production. The prospect is not subject to the
Aera Agreement. We own a 100% working interest in the prospect.
PRIMEX/AERA EXPLORATION AGREEMENTS
On September 15, 1999, we entered into an agreement with Prime Natural
Resources, LLC (formerly Prime-X Oil & Gas LLC) ("Primex") to jointly conduct a
3-D seismic survey in the southern San Joaquin Basin in order to identify new
oil and gas prospects over an area of approximately 80,000 acres.
Effective October 1, 1999, we entered into an exploration agreement with Primex
and Aera in which we agreed to pool certain of our respective acreage positions
in the southern San Joaquin Basin in order to share the costs of carrying out
the program and broaden our respective interests in the area. Aera will retain
an equal interest in the data generated from the 3-D seismic program, but all
costs of carrying out the program will be borne equally by Primex and ourselves.
The pooled acreage under the agreement is divided into four areas and our
participating interest ranges from 17.5% to 50%. The survey is intended to
identify prospects for exploration drilling. Once prospects have been
identified, each party may elect to participate in a drilling program.
TEXAS PROPERTIES
In April, 2000, we entered into an agreement with Discovery Operating, Inc.
("Discovery") an independent oil and gas company. Discovery holds certain leases
and is a party to certain farm-out agreements relating to over 9,100 gross acres
of oil and gas exploration property in the Spraberry Trend of the West Texas
Permian Basin in Midland County. Under the terms of our agreement with
Discovery,
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we hold, until payout of our costs, a 62.5% working interest in the property.
Upon payout, we will retain a 50% interest. Discovery is the operator of the
project. We have drilled 22 wells on the property to date, and 19 of the wells
are now producing approximately 500 barrels of oil equivalents per day. During
the remainder of 2001, we expect to drill an additional 30 wells on the
property, and, by the end of 2001, to have approximately 49 wells on production.
Ninety new wells will be required to develop our proved acreage in the Spraberry
Trend. We have the option to continue or terminate the drilling program on a
well-by-well basis.
In December, 2000 and during the first quarter of 2001, we acquired over 28,400
gross (20,700 net) acres in the Bossier gas sands, located in East Texas. We
have identified six prospects where we expect to commence drilling in the third
quarter of 2001. Our working interest in the Bossier sands is subject to
leasehold burdens and a 9.375% net profit interest. We intend to continue
increasing our leased acreage in the Bossier area.
CHINA PROPERTIES
We hold interests in China through Sunwing. We acquired all of the issued and
outstanding common shares of Sunwing in June, 1999 pursuant to a statutory
arrangement under the Yukon Business Corporations Act.
DAGANG PROJECT
Our principal asset in China is a production sharing contract dated September 8,
1997 (the "Dagang Contract") with CNPC. PetroChina Company Limited
("PetroChina"), a subsidiary of CNPC, administers the Dagang Contract on CNPC's
behalf. The Dagang Contract is a production sharing arrangement covering an area
of 22,400 gross acres divided into six blocks in the Kongnan oilfield in Dagang,
Hebei Province, China (the "Dagang Project").
The Dagang Contract is effectively a licensing arrangement in which we are
obliged to meet 100% of the development costs for which we receive the right to
operate the Kongnan oilfield for a period of 20 years and participate in the oil
production from the field. If and when we commence production at the Dagang
Project, after deduction of royalties, value added tax and operating costs, we
will be entitled to 82% of the remainder of the net revenue generated from oil
production until our development costs have been recovered in full. Thereafter,
we will be entitled to receive 49% of the net revenue.
We have a marketing arrangement with CNPC whereby we have the option of either
exporting our share of oil production or selling it to CNPC. We currently sell
our crude oil to CNPC at a price equal to the three month 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.
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. 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 to pay royalties as we do
not expect that any of the blocks will produce more than 500,000 tonnes per
annum. Our entire interest in the Dagang Project will revert to CNPC if we
terminate the Dagang Contract at the conclusion of the pilot testing phase, or
at the end of the 20-year production period. We may elect to abandon the project
at any time before the end of the 20-year production period.
We have farmed out a 20% working interest in the Dagang Contract to Nippon.
Nippon earned its working interest by funding $6 million of pilot testing
expenditures on the Dagang Project. We remain the operator of the Dagang
Project.
In February, 2001, we completed the pilot testing phase and we are now preparing
to submit an overall development plan for the Dagang Project to CNPC, for its
approval during the third quarter of 2001. The
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development phase will start after CNPC approval. We contemplate drilling
approximately 120 new wells and reworking approximately 50 to 82 existing wells.
We estimate that, in order to complete the development phase, we will need to
invest in excess of $150 million over four years.
DAQING PROJECT
We are also a party to a production sharing contract dated August 8, 1996 with
CNPC (the "Daqing Contract") which covers an area of 8,100 gross acres in the
Zhaozhou oilfield in Daqing, Heilongjiang Province, China (the "Daqing
Project"). PetroChina also administers the Daqing Contract on CNPC's behalf.
The terms of the Daqing Contract are substantially the same as the Dagang
Contract except we will be entitled to 85% of the net revenue from oil
production until we have recovered our development costs. Our royalty payment
obligations are the same as for the Dagang Project except that royalties are
calculated on the basis of production from the entire project instead of
individual blocks. CNPC is also entitled to a 2.5% priority allocation of oil
production from the Daqing Project.
Like our marketing arrangement at Dagang, we have the option of either exporting
our share of oil production or selling it to CNPC. We currently sell our Daqing
Project crude oil to CNPC at a price equal to the three month rolling average
price of Daqing crude oil as published by Platts. The average price over the
last three years is approximately $1.50 per barrel less than the WTI price.
We successfully completed our pilot testing program in 1998. However, we delayed
preparation of our overall development plan due to low world oil prices and in
order to concentrate our efforts on the larger Dagang Project. CNPC agreed to
operate the field pending their review and approval of our overall development
plan for the Daqing Project. CNPC approved our overall development plan in
February 2001 and, as a result, we expect to resume control of Daqing Project
operations during the first half of 2001. Our overall development plan
contemplates the drilling of approximately 60 new wells during a two year
development phase which is scheduled to begin in the second half of 2001. We
estimate that, in order to complete the development phase, we will need to
invest approximately $23 million over two years.
SICHUAN BASIN
In February, 2001, we signed two memoranda of understanding with PetroChina.
These memoranda give us the exclusive right to negotiate petroleum contracts
with PetroChina in three land blocks in Sichuan Province.
We have agreed with PetroChina to carry out joint feasibility studies on the
Zitongxi, Zitongdong and Yudong blocks located in the Sichuan Basin,
approximately 930 miles southwest of Beijing. These blocks 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, subject
to Chinese government approvals. We will have the exclusive right to negotiate
production sharing contracts with PetroChina for a period of four months
following receipt of government approval in respect of the Yudong block and for
a period of nine months from February 2001 in respect of the Zitongxi and
Zitongdong blocks.
PetroChina has drilled 39 wells on the three blocks. Twenty-six of these wells
have been classified as producing gas wells. PetroChina has only production
tested eight of the estimated 38 hydrocarbon bearing structures located on the
three blocks.
RUSSIA PROPERTIES
When we commenced business in 1996, our original business plan was to acquire,
explore, develop and operate oil and gas projects in Russia. We acquired a 50%
interest in an exploration and development project at the Kalchinskoye field in
western Siberia ("Tura"), a 50% interest in an exploration block adjacent to
Tura ("Radonezh") and a 50% interest in an enhanced oil recovery project in the
Krasnodar
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region near the Black Sea. In 1998, we concluded that the Krasnodar project was
uneconomic and we relinquished our interest in it.
We enjoyed greater success with our development and rehabilitation activities at
Tura and succeeded in tripling production over an 18 month period. We curtailed
investment under our development program at Tura in the second quarter of 1998
when our Russian partner in the Tura project, OJSC Tyumeneftegaz, and its parent
company Tyumen Oil Company commenced a series of actions against us in the
Russian courts seeking to deprive us of our interest in Tura. We also suspended
our exploration program at Radonezh. Following almost two years of legal
proceedings in the Russian courts and international arbitration proceedings in
Stockholm, we reached a settlement in August, 2000 under which we received
approximately $29 million in cash and divested all of our remaining Russian
project interests. See Item 3. "Legal Proceedings".
PERU PROPERTIES
In August, 1998, we acquired a 50% participating interest in a 2.5 million acre
concession in the Ucayali basin of east-central Peru known as Block 71 by
funding $13.5 million in drilling and related expenditures. Our initial
exploratory well on Block 71 was plugged and abandoned as a dry hole in
December, 1998. The well, drilled to a total depth of 7,123 feet, encountered
minor shows of oil and gas at various intervals, but was determined to be
non-commercial. We relinquished our interest in Block 71 during 2000.
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
Item 7. "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Risk Factors."
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 are 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.
In Australia, operations are subject to regulation under various state,
territory and commonwealth (federal) environmental laws. At the federal level,
the Department of Primary Industry and Energy has regulatory responsibility.
This responsibility is shared at the state/territory level with the Department
of Minerals and Energy. Various environmental protection agencies provide advice
to these departments.
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
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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, 2001, we had 70 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 and Russia. In
China, proceeds from the sale of oil produced is 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 -- $21.27). Average
production costs include lifting costs, but exclude depreciation, depletion and
amortization, royalties, income taxes, interest and selling administrative and
other expenses.
AVERAGE SALES PRICE AVERAGE PRODUCTION COST
-------------------------- --------------------------
2000 1999 1998 2000 1999 1998
------ ------ ------ ------ ------ ------
CRUDE OIL AND NATURAL GAS LIQUIDS
($/BOE)
Russia.............................. -- $ 4.68 $ 7.43 -- $ 2.49 $ 2.86
United States....................... $27.52 -- -- $10.00 -- --
The following tables set forth the number of productive crude oil wells (both
producing wells and wells capable of production) in which we held an interest at
December 31, 2000 and 1999:
2000 1999
-------------------- --------------------
OIL OIL
-------------------- --------------------
GROSS(1) NET(2) GROSS(1) NET(2)
-------- -------- -------- --------
Russia......................................... -- -- -- --
United States.................................. 29 25.6 -- --
China.......................................... 9 6.7 4 3.4
- - ---------------
(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 drilling of net crude oil and natural gas wells
EXPLORATORY
PRODUCTIVE
-----------------------------
2000 1999 1998
------- ------- -------
Russia...................................................... -- -- 0.5
United States............................................... -- -- --
China....................................................... -- -- --
------- ------- -------
Total....................................................... 0 0 0.5
======= ======= =======
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DRY
-----------------------------
2000 1999 1998
------- ------- -------
Russia...................................................... -- -- 1
United States............................................... 2 2 --
China....................................................... -- -- --
------- ------- -------
Total....................................................... 2 2 1
======= ======= =======
DEVELOPMENT
PRODUCTIVE
-----------------------------
2000 1999 1998
------- ------- -------
Russia...................................................... -- -- 2
United States............................................... 25.6 -- --
China....................................................... 3.3 3.4 --
------- ------- -------
Total....................................................... 28.9 3.4 2
======= ======= =======
DRY
-----------------------------
2000 1999 1998
------- ------- -------
Russia...................................................... -- -- --
United States............................................... 2 -- --
China....................................................... -- -- --
------- ------- -------
Total....................................................... 2 0 0
======= ======= =======
The following tables set forth our holdings of developed and undeveloped oil and
gas acreage at March 1, 2001:
DEVELOPED UNDEVELOPED
-------------------- --------------------
GROSS NET GROSS NET
ACRES(1) ACRES(2) ACRES(1) ACRES(2)
-------- -------- -------- --------
United States....................................... 2,465 1,864 117,338 68,026
China(3)............................................ 1,976 927 28,479 13,356
- - ---------------
(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.
As of March 1, 2001 we were in the process of drilling one well in Texas. A
total of five wells were started in Texas in 2001, four of which reached total
depth by March 1, 2001 and will be completed and put on production in due
course.
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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, 2000. Estimates for our China
operations were prepared by independent petroleum consultants Gilbert Laustsen
Jung Associates Ltd. Estimates for our United States operations were prepared by
independent petroleum consultants Duke Engineering & Services and Joe C. Neal &
Associates.
OUR SHARE OF BEFORE TAX CASH OUR SHARE OF AFTER TAX CASH
OUR SHARE FLOWS FLOWS
--------------- IN THOUSANDS OF DOLLARS IN THOUSANDS OF DOLLARS
OIL GAS DISCOUNTED AT: DISCOUNTED AT:
------ ------ ------------------------------ ------------------------------
(MBBL) (MMCF) 0% 10% 15% 0% 10% 15%
PROVED RESERVES(1)
United States...................... 4,773 6,296 $ 67,604 $ 28,133 $ 19,501 $ 46,103 $ 19,202 $ 13,585
China.............................. 21,021 -- 278,287 120,687 83,411 196,954 82,034 54,989
------ ----- -------- -------- -------- -------- -------- --------
25,794 6,296 $345,891 $148,820 $102,912 $243,057 $101,236 $ 68,574
====== ===== ======== ======== ======== ======== ======== ========
- - ---------------
(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.
ITEM 3. LEGAL PROCEEDINGS
We jointly formed Tura with TNG in 1996, through a Russian closed stock company,
to enhance production at the Kalchinskoye oil field in the Tyumen Region of
western Siberia. At that time, the Russian government held a controlling
interest in TNG's parent Tyumen Oil Company. During 1997 and the first half of
1998, we achieved substantial technical success at the Tura Project. Our
introduction of western capital and technology to the project resulted in daily
production at the field more than doubling, from 4,900 barrels of oil per day to
11,500 barrels of oil per day.
In May, 1998, shortly after the privatization of Tyumen Oil Company, its new
owners began to assert direct management control over TNG and began to dispute
the terms of our Tura joint venture. They then commenced a number of legal
actions against the Tura joint venture company in the Tyumen regional courts
challenging the validity of the foundation agreement which created the Tura
joint venture company and the transfer from TNG to the Tura joint venture
company of the licenses required to develop the Kalchinskoye oil field.
In their initial series of court actions, TNG and Tyumen Oil Company obtained
temporary injunctions against the Tura joint venture company. These injunctions
did not materially affect production, but severely restricted Tura's ability to
sell its oil during the second half of 1998. In the face of TNG's actions, we
withheld planned capital contributions to the Tura project for further
development of the field and limited Tura's operations to maintenance
activities. In early 1999, Tura succeeded in negotiating an interim sales
agreement with Tyumen Oil Company, with the assistance of the Russian Ministry
of Fuel and Energy. This agreement facilitated the sale of 1998 year end
inventory as well as production through the second quarter of 1999. While the
terms of the agreement were unfavourable to Tura, oil sales produced cash flow
which allowed Tura to maintain oil field operations while the dispute continued.
This interim agreement expired in June, 1999.
Throughout the dispute, Tura was involved in a series of legal proceedings with
TNG and Tyumen Oil Company in the Russian courts, both at the regional level in
Tyumen and at the appellate level in the senior courts in Moscow. Although we
argued that the Russian court decisions were procedurally flawed and legally
incorrect, TNG and Tyumen Oil Company prevailed in certain key judicial
decisions and were ultimately successful in effectively invalidating the Tura
foundation agreement and the license transfers. TNG was subsequently able to
obtain new licenses for the Kalchinskoye field which superseded Tura's
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licenses. As a consequence, Tura's direct production and oil sales rights were
revoked and, as of June 1999 the Tura joint venture company was replaced as
operator of the field.
In June, 1999, we commenced international arbitration proceedings against TNG
under the authority of the Chamber of Commerce of Stockholm, Sweden pursuant to
the UNCITRAL Arbitration Rules. We alleged that TNG willfully and materially
breached numerous provisions of the Tura joint venture company's charter and
acted in bad faith and in willful disregard of its contractual obligations.
Through the arbitration, we sought an award of approximately $110 million
representing, among other things, recovery of our investment and lost future
profits.
In August, 2000, we entered into a settlement agreement with TNG, Tyumen Oil
Company and Stesana Enterprises Limited ("Stesana"). Under the terms of the
settlement agreement, we disposed of all of the outstanding shares of the two
Cypriot subsidiaries through which we held our interest in Tura and in the
adjacent Radonezh exploration project. As consideration, we received
approximately $29 million in cash from the acquiror, Stesana. We also agreed
with TNG and Tyumen Oil Company to terminate all legal proceedings in Russia and
all proceedings in connection with the Stockholm arbitration. All such
proceedings have now been terminated.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET INFORMATION
Our common shares are traded on the NASDAQ National Market and The Toronto Stock
Exchange.
The high and low sale prices of our common shares as reported on the NASDAQ
National Market for the third and fourth quarter of 2000 and The Toronto Stock
Exchange for each quarter during the past two years are as follows:
NASDAQ NATIONAL MARKET (IVAN)
2000
-----------------------------------
1ST Q 2ND Q 3RD Q(1) 4TH Q
----- ----- -------- -----
High................................................. -- -- 4.6875 6.75
Low.................................................. -- -- 4.00 3.875
- - ---------------
(1) Our common shares did not commence trading on the NASDAQ National Market
until August 28, 2000.
THE TORONTO STOCK EXCHANGE (IE)
(CDN.$)
2000 1999
-------------------------------- --------------------------------
1ST Q 2ND Q 3RD Q 4TH Q 1ST Q 2ND Q 3RD Q 4TH Q
----- ----- ----- ----- ----- ----- ----- -----
High...................... 4.20 7.20 7.50 9.80 0.60 2.20 4.90 3.95
Low....................... 2.50 2.61 5.95 6.00 0.32 0.43 2.10 2.50
On March 1, 2001, the closing prices for our common shares were $4.6875 on the
NASDAQ National Market and Cdn.$7.15 on The Toronto Stock Exchange.
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HOLDERS OF COMMON SHARES
As at March 1, 2001, a total of 127,047,362 of our common shares were issued and
outstanding and held by 89 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 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 2001 is Cdn.$209 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 (the "Convention"). Currently, under the
Convention, the rate of Canadian
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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%.
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. For a United States GAAP reconciliation, see Note 14
to our financial statements. See also Item 7. "Management's Discussion and
Analysis of Financial Condition and Results of Operation".
The following table shows selected financial information for the periods
indicated:
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- ---------- ---------- ---------
(STATED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE AMOUNTS)
Revenues........................... $14,063 $ 6,210 $ 12,752 $ 15,077 $ 24
Total assets....................... 99,800 47,659 49,442 120,483 22,752
Long-term debt..................... Nil Nil 1,763 1,718 Nil
Net earnings (loss)................ 5,429 (7,802) (70,677)(1) (2,185) (1,593)
Net earnings (loss) per share...... 0.05 (0.08) (0.79) (0.03) (0.22)
- - ---------------
(1) Includes asset writedown of $70.2 million. See Note 9 to our financial
statements under Item 8 in this 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 difference between Canadian and U.S.
GAAP which affects our financial statements is that under U.S. GAAP the
determination of earnings per share is calculated excluding shares held in
escrow, and dilutive earnings per share is calculated on the treasury method
rather than the imputed earnings method applied in Canada.
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 7 to the financial statements and potential
conversion of the debt, Note 6, do not have a material dilutive effect on the
earnings per share.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2000 1999 1998 1997 1996
------ -------- --------- -------- --------
(STATED IN THOUSANDS OF U.S. DOLLARS, EXCEPT PER SHARE
AMOUNTS)
Net earnings (loss) per share............ 0.05 (0.09) (1.10) (0.04) (0.22)
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 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. See Items 1 and 2. "Business and Properties -- Oil and Gas Properties
- - --California Properties".
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. See Items 1 and 2. "Business and Properties -- Oil and Gas
Properties -- Texas Properties".
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. See Items 1 and 2. "Business and Properties -- Oil and Gas
Properties -- China Properties".
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. See Items 1 and 2. "Business and Properties -- Gas-to-Liquids
Projects."
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. See Item 3. "Legal Proceedings".
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 for the year ended
December 31, 2000 was $11.8 million, up 90% from the cash flow deficiency 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.
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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.
2000
---------------------------
MIDWAY SPRABERRY TOTAL
------ --------- ------
Net Production
Oil -- Bbls............................................... 19,096 10,981 30,077
Gas -- Mcf................................................ -- 4,816 4,816
Boe....................................................... 19,096 11,833 30,929
Boe per day -- exit rate December 31, 2000.................. 253 383 636
Per Boe
Average sales price....................................... $25.39 $30.96 $27.52
------ ------ ------
Operating costs........................................... 13.56 4.25 10.00
Production taxes.......................................... -- 1.50 0.57
------ ------ ------
13.56 5.75 10.57
------ ------
Depletion, Depreciation and Amortization.................. 8.70
------
19.27
------
Net....................................................... $ 8.25
======
Total revenue from our oil and gas operations was $851,000. Our operating costs
at South Midway Sunset were unusually high due to facility rental costs
associated with start-up operations. We expect to reduce our operating costs at
South Midway Sunset to the $4.00 per barrel range during the second quarter of
2001. Operating costs we reported in our statement of income include allocated
head office engineering support costs of $0.5 million. Depletion, depreciation
and amortization costs are high due to the nature of the South Midway Sunset and
Spraberry Trend projects. While South Midway Sunset and Spraberry Trend require
high development and facility costs to exploit limited reserves, both provide
good economic returns at current oil and natural gas prices.
PROJECT IDENTIFICATION COSTS
We remain committed to the geographical diversification of our oil and gas
activities. We follow the practice of expensing the costs we incur in pursuing
and investigating new projects. With the acquisition of our Syntroleum master
license, we have intensified our search for new international oil and gas and
GTL projects. During 2000, we incurred $3.7 million, up $2.0 million from the
$1.7 million incurred in 1999, in costs associated with international project
opportunities that we have rejected or that we were still investigating at
year-end. Once we obtain rights or interests in a new project we capitalize the
costs we incurred in obtaining the project.
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GENERAL AND ADMINISTRATION
We incurred general and administrative costs of $2.8 million during 2000, up
$0.2 million from the $2.6 million we incurred in 1999. We attribute the bulk of
the increase to the costs associated with listing on NASDAQ in 2000.
OTHER INCOME AND EXPENSES
Interest income represents income we earned on our excess cash balances held
during the year. The increase of approximately $0.5 million during 2000 arises
from the additional funds available from two private placements we completed
during the year and from the divesture of our Russian projects. Russian
litigation costs (down approximately $0.3 million from 1999), depletion and
depreciation (down $1.3 million from 1999) and asset write downs (down $2.5
million from 1999) all result from the divesture of our Russian projects and the
settlement of our legal dispute with our Russian partner in August 2000.
INCOME TAXES
We have significant tax losses available to carry forward and reduce taxes
otherwise payable. Given the uncertainty as to the utilization of these tax loss
carry-forwards, we have followed the practice of recording a provision against
the tax benefit asset resulting from these losses. In 2000, our expected income
tax expense on the income reported on our statement of income has been reduced
by the benefit of tax assets not previously recorded.
EXPLORATION AND DEVELOPMENT ACTIVITIES
During 2000, we carried out an extensive exploration program in the San Joaquin
Valley on acreage primarily acquired under our Aera Agreement. We participated
in an 80,000 acre 3-D seismic shoot, the largest ever carried out in the San
Joaquin Valley. We purchased an additional 7,000 acres of 3-D seismic previously
shot in the same area. We also continued interpreting over 2,000 miles of 2-D
seismic acquired in 1999. We submitted preliminary prospects to Aera for its
review in 14 areas covered by the Aera Agreement. We are developing numerous
drillable prospects within those preliminary prospect areas and, during 2000, we
submitted six drillable prospects to Aera. See Items 1 and 2. "Description of
Business and Properties -- Oil and Gas Properties -- California Properties --
Aera Agreement". At South Midway Sunset, where we have a 100% interest, we
commenced a drilling program, details of which are discussed above under
"Production". In addition to the South Midway Sunset drilling program, we
drilled three other exploration wells in the San Joaquin Valley during 2000, two
of which were dry and abandoned. We are still testing the third well to
determine its commercial potential. We identified the location of our first deep
gas well at Northwest Lost Hills and we expect to spud the well during the
second quarter of 2001.
In Texas, we drilled 16 successful wells in our Spraberry Trend acreage in West
Texas by year-end and an additional four wells during the first two months of
2001. Through a series of transactions in late 2000 and early 2001, we were
successful in acquiring an interest in over 28,400 gross (20,700 net) acres in
the Bossier gas sands in East Texas. We expect to commence drilling at Bossier
during the third quarter of 2001.
At our Dagang Project in China, we completed our pilot testing phase in
February, 2001. During 2000, as part of the pilot testing phase, we placed in
production four new wells. We placed our initial well on water injection late in
2000 to evaluate the waterflood potential of the field. We also placed on
production a fifth well in early 2001. We have decided to proceed to the
development stage of our Dagang Project, which will require the submission of an
overall development plan to the Chinese government for approval. We expect to
submit it to the Chinese government during the second half of 2001. In the
interim, we will continue to operate the pilot wells with production revenue
accruing to us. At our Daqing Project, our overall development plan was approved
in February, 2001 and we expect to start implementing it during the third
quarter of 2001. Although we completed the pilot testing phase of
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the Daqing Project in 1998, we delayed submitting our overall development plan
to the Chinese government because of low world oil prices and in order to focus
our attention on our Dagang Project. In the interim, we agreed with CNPC to
temporarily cede our operatorship of the Zhaozhou field pending completion and
approval of our overall development plan for the Daqing Project. Having
submitted and received approval for the Daqing Project, we expect to resume our
role as operator during the first quarter of 2001.
The following summarizes the production and revenue we realized from the pilot
testing phase of our Dagang Project. Prior to deciding to proceed to the
development phase, this revenue was credited to the China cost pool for
accounting purposes. All sales of oil are at or about WTI less approximately
$2.00 for quality and transportation. We receive all proceeds in U.S. dollars
offshore China.
2000 1999
---------- -------
Oil production (net) -- Bbls................................ 102,708 4,334
Price per Bbl realized...................................... $ 28.26 $ 21.27
Total proceeds.............................................. $2,903,000 $92,203
Our total capital spending on oil and gas operations during 2000, compared to
1999, was as follows:
2000 1999
------- -------
(IN THOUSANDS)
Capital Expenditures:
United States............................................. $22,816 $ 9,565
China..................................................... 5,676 13,280
Russia.................................................... -- 1,283
Peru...................................................... -- 80
------- -------
$28,492 $24,208
======= =======
Comprised of:
Property acquisition...................................... $ 6,392 $11,346
Royalty acquisition....................................... 1,157 4,023
Seismic................................................... 3,840 3,442
Exploration............................................... 667 1,311
Development............................................... 19,376 4,178
------- -------
31,432 24,300
Less: China oil production................................ (2,940) (92)
------- -------
$28,492 $24,208
======= =======
GAS-TO-LIQUIDS
During 2000, we acquired a master license from Syntroleum which allows us to use
Syntroleum's proprietary GTL technology in an unlimited number of GTL projects
throughout the world excluding North America, China and India. The Syntroleum
GTL process converts natural gas into synthetic liquid hydrocarbons that can be
utilized to develop cleaner-burning diesel fuel and other synthetic petroleum
products. We have commenced engineering studies and review of several potential
sites for our first GTL plant and we are in advanced discussions with national
petroleum corporations in the Middle East and Asia.
On October 5, 2000, we signed a letter of intent with Syntroleum to acquire a
13% non-recourse partnership interest in Syntroleum's Sweetwater GTL project
under development in Western Australia. The plant, which will be located on the
Burrup Peninsula in Western Australia, will convert natural gas contracted from
the North West Shelf Venture Partners into ultra clean synthetic specialty
products, such as lubricants, industrial fuel and paraffins, as well as
synthetic fuels. See Items 1 and 2. "Business and Properties -- Gas to Liquids
Projects."
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LIQUIDITY AND CAPITAL RESOURCES
We intend to pursue an aggressive capital expenditure program throughout 2001.
At Spraberry and at South Midway Sunset we plan to continue our ongoing
development programs. During 2001 we expect to drill nine development wells per
quarter at Spraberry and an additional six development wells at South Midway
Sunset. We consider both Spraberry and South Midway Sunset to be low risk, low
cost projects which should continue to provide good economic returns at current
commodity prices. Should prices weaken, we will review our development program
and adjust to either delay or curtail our activities on these projects.
Our exploration activities during 2001 will be concentrated in Southern
California and in the Bossier sands. We plan to spud our first deep gas
exploration well at Northwest Lost Hills during the second quarter. We may also
drill up to five additional exploration wells in the San Joaquin and Ventura
Basins during the balance of the year, subject to rig availability and funding.
In China, we will focus our 2001 activities on submitting a full development
plan for our Dagang project to CNPC during the third quarter, and on initiating
our development plan at the Daqing project. Although we expect Daqing to be more
capital intensive during 2001 than Dagang, we have the ability to extend the
development of Daqing over a three year period if necessary. All income derived
from production from the pilot test wells at Dagang and Daqing during this
period will be for our account.
We expect that Syntroleum will be successful in arranging project financing for
the Sweetwater GTL project in Australia before the end of 2001. Once Syntroleum
arranges project financing, we will be required to complete our acquisition of a
13% equity interest in the project by remitting $19 million. Since GTL project
development is our long-term core strategy, we will continue to actively pursue
opportunities to construct GTL conversion plants on top of existing stranded gas
fields.
For 2001, we have budgeted approximately $66 million for drilling and
development plus an additional $19 million for the Sweetwater project. Planned
capital expenditures may increase if we are successful in acquiring an
additional GTL project during 2001 but we can give no assurance that we will do
so.
At December 31, 2000, we had $29.7 million in cash. Other than a $1 million
convertible debenture, we have no outstanding debt. We have not previously
pursued any credit facilities due to our success in raising capital through the
sale of equity securities. However, we can give no assurance that this source of
funding will continue to be available in the future.
Excluding any additional capital expenditures we may incur if we acquire an
additional GTL project during 2001, we will require external financing, net of
existing financial resources and internally generated cash flow, of
approximately $45 million to carry out all our planned activities, including
overhead and the pursuit of new opportunities. Although we intend to raise the
funds we need through the sale of equity securities or from production loans
secured against our producing properties, we can give no assurance that we will
be successful in doing so. If we are unable to raise the necessary funds, we
will have to prioritize our activities, which may result in 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.
YEAR ENDED DECEMBER 31, 1999
OVERVIEW
During 1999, we continued to increase the overall size of our land position in
the San Joaquin Valley of California through acquisitions. We purchased Diatom,
a holder of extensive exploration rights in the area. We also acquired a series
of royalty interests in the same area. We intend to continue adding to our oil
and gas interests in the San Joaquin Valley whenever attractive opportunities
arise.
In June, 1999, we acquired Sunwing by issuing approximately 17.5 million of our
common shares to Sunwing's former shareholders. Through Sunwing, we hold two
production sharing agreements with CNPC
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which entitle us to participate in development projects in two of China's
largest oil producing regions and we have acquired the services of Sunwing's
senior management personnel who have excellent technical credentials and good
working relationships with CNPC and the relevant Chinese government ministries
and agencies.
Throughout 1999, the status of our investment in the Tura project in Russia
remained unresolved. TNG, our partner in the Tura Project, and its parent,
Tyumen Oil Company, assumed effective control of the project in June, 1999. TNG
continued its efforts in the Russian courts to deprive the Tura joint venture
company, through which we hold our interest in the project, of its oilfield
assets and equipment, without compensation, and to obtain a reimbursement of
revenues received by the Tura joint venture company from prior oilfield
production. To that end, TNG obtained judgement against the Tura joint venture
company and a writ of execution for the sale of its assets. An auction of the
assets was held on May 16, 2000. No bids were received and, consequently, the
bailiff transferred equipment worth 256 million rubles (approximately US$9.23
million based on then prevailing currency exchange rates) to TNG in settlement
of its claim against the Tura joint venture company. We continued to pursue
avenues of appeal in the Russian courts seeking to obtain a satisfactory remedy
through Russian legal proceedings. We also initiated international arbitration
proceedings in Stockholm, seeking recovery of our investment and lost future
profits.
Based on the uncertain status of our investments in Russia (including our
investment in the Radonezh project, which was not under legal challenge but was
suspended pending resolution of the Tura dispute, and certain equipment owned by
our Cypriot subsidiaries), we stopped proportionately consolidating the results
of our Russian operations with our other operations for financial reporting
purposes as at June 30, 1999. After June 30, 1999, we recorded our investments
in the Russian projects at cost, less an impairment provision we made as at
December 31, 1998 in accordance with GAAP. We capitalized all costs, other than
legal costs, associated with these investments, and amounts we recovered were
applied to reduce the carrying value of the investments.
For financial statement presentation in 1999, we assumed that we would be
successful in reaching a negotiated settlement of the dispute sufficient to
recover the recorded carrying value of our investment in the Russian projects.
As at December 31, 1999, we recorded the remaining value of our investment in
Russian operations at $16.2 million. This amount represented the residual value
of our investment in the Russian projects, after providing for impairment of
$46.7 million in 1998, plus $442,000 in costs we incurred during 1999 to
maintain a presence at the Tura site after we lost control of field operations,
less direct remittances of $2.9 million we received from the Tura joint venture
company as proceeds from the sale of oil, excess supplies and equipment.
OPERATIONS
In 1999, we lost $7.8 million ($0.08 per share), including $2.5 million for
impairment of equipment held for resale, compared to a loss of $70.7 million
($0.79 per share), also including a provision for impairment of oil properties
and equipment held for resale of $70.2 million, during 1998. Our cash-flow
deficiency from operating activities during the year was $6.2 million, compared
to positive cash flow from operating activities of $4.7 million during 1998. In
1999, we received $735,000 as the proceeds of the issuance of common shares
pursuant to the exercise of stock options and we invested cash of $10.7 million
in capital assets ($30.1 million in 1998). In 1999, we realized $4.3 million
from the sale of equipment we originally intended to use at the Tura project but
retained and sold after the Tura project dispute arose. As of December 31, 1999
we held an additional $3.3 million of equipment for sale.
During the period from January to June, 1999, when we lost control of the Tura
project, we incurred a loss of $222,000 in respect of our Russian operations.
From January until June, 1999 our share of production from the project was
806,679 barrels of oil (4,980 barrels per day, compared to 4,995 barrels per day
during 1998). Our share of oil sales in 1999 was $5.5 million (representing
1,167,289 barrels at an average price of $4.68 per barrel), primarily into
Russian domestic markets, compared to $11.0 million
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($7.43 per barrel) received during 1998. This reduction in oil revenue of $5.5
million resulted from reduced volumes of oil (310,00 barrels) being available
for sale as a consequence of our loss of operational control in June, 1999.
Depressed domestic oil prices in Russia were also a factor because, as a result
of TNG's litigation against the Tura joint venture company, TNG was able to
force Tura to sell all of its oil in Russian domestic markets. Our operating
cost per barrel in 1999 dropped to $2.49 per barrel, a decrease of $0.37 per
barrel from that incurred in 1998, primarily as a result of reducing our staff
and activity levels. Sales in 1999 were primarily in the domestic Russian market
and, as a consequence, transportation costs and excise taxes, which are levied
on export sales only, were reduced from the 1998 levels of $0.90 and $1.88 by
$0.70 per barrel and $0.96 per barrel, respectively. Depletion per barrel during
1999 amounted to $2.00 compared to $3.04 per barrel, before provision for
impairment, in 1998. In addition, Tura recovered operating costs for the month
of June when all production was for the account of TNG. Our share of this
additional revenue amounted to $296,000. All petroleum revenues reported in
1999, 1998 and 1997 were from our share of Tura's sales. Since June 1999, there
have been no petroleum sales from the Tura project. Activities at the Tura
project during the latter half of 1998 and most of 1999 consisted primarily of
selling oil production, disposing of excess supplies and equipment and defending
the numerous legal actions brought by TNG and its parent company, Tyumen Oil
Company. For the period from June 30, 1999 to December 31, 1999, we incurred
continuing costs of $442,000 to maintain our presence at the Tura project. These
costs were partially offset by the $380,000 we received from Tura representing
proceeds from the sale of excess supplies and equipment. In total, during 1998
and 1999 the Tura joint venture company was able to directly remit to us $2.4
million and $2.9 million, respectively, from proceeds received from the sale of
oil, excess supplies and equipment.
We incurred general and administrative costs during 1999 of $5.3 million, which
was $2.4 million more than we incurred during 1998. Although we incurred
additional costs of approximately $500,000 in establishing our business in
California and funding additional administrative costs we assumed when we
acquired Sunwing, the bulk of the 1999 increase was attributable to additional
legal and professional fees of $1.1 million incurred preparing our international
arbitration claim in Stockholm and costs of $1.7 million incurred pursuing other
project opportunities. For presentation purposes in the 2000 financial
statements these latter two items have been reclassified and presented
separately in the consolidated statement of income.
We incurred capital expenditures of $24.2 million during 1999 (including $13.4
million through the issue of common shares) to acquire Sunwing ($10.5 million),
Diatom ($548,000) and certain overriding royalty rights ($4.0 million), to
increase our land holdings in the San Joaquin Basin and to obtain additional
technical information with respect to our California properties ($5.0 million),
and to implement our Dagang Project's pilot testing program in China ($2.8
million). In addition, our share of capital expenditures incurred and funded by
our Russian operations in early 1999, amounted to $1.3 million. The nature of
the 1999 expenditures, compared to those in 1998 is as follows:
1999 CAPITAL EXPENDITURES
------------------------------- 1998
BY ISSUE OF CAPITAL
SHARES CASH TOTAL EXPENDITURES
----------- ------- ------- --------------
(IN THOUSANDS) (IN THOUSANDS)
Property Acquisition
Proved........................................ $ 6,936 $ 532 $ 7,468 $ 100
Unproved...................................... 3,381 497 3,878 250
Royalty rights................................ 3,163 860 4,023 --
Development..................................... -- 4,086 4,086 9,517
Exploration..................................... -- 4,753 4,753 20,191
------- ------- ------- -------
$13,480 $10,728 $24,208 $30,058
======= ======= ======= =======
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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.
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 ADVERSELY AFFECT OUR FINANCIAL CONDITION.
Since we lost effective control of our interest in the Tura project in Russia in
1999, we have only recently resumed generating limited revenue from the
production and sale of oil. We have no sustained history of earnings and we have
operated at a loss since we commenced business. 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 January and February 2000, we completed approximately $14 million in
equity financing and in October 2000, we completed approximately $25 million in
equity financing. We also received approximately $29 million in August, 2000
from the sale of our Russian project interests. 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. 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 our rights in existing oil and gas property interests. Our limited
operating history may make it difficult to obtain future financing.
OUR EXPLORATION AND DEVELOPMENT PROPERTIES MAY NOT CONTAIN ANY SIGNIFICANT
PROVEN RESERVES BEYOND THOSE DISCLOSED IN THIS ANNUAL REPORT. ANY
FORWARD-LOOKING EXPLORATION, DEVELOPMENT AND PRODUCTION COST DATA CONTAINED IN
THIS ANNUAL REPORT ARE ONLY ESTIMATES, AND OUR ACTUAL PRODUCTION, REVENUES AND
EXPENDITURES MAY DIFFER MATERIALLY FROM THESE ESTIMATES.
We have not determined that materially significant proven reserves exist on any
of our oil and gas properties beyond those disclosed in this Annual Report. Oil
and gas 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 proven reserves, and
there can be no assurance that commercial quantities of oil and gas deposits
will be discovered sufficient to enable us to recover our exploration and
development costs. 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. We
cannot assure you that actual exploration cost will not exceed projected cost.
OUR BUSINESS MAY BE ADVERSELY AFFECTED 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 have a material adverse effect on the results of our
operations and 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 have a material adverse effect on our business and results
of operations.
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OUR OPERATIONS MAY BE ADVERSELY AFFECTED IF WE ALLOCATE SIGNIFICANT FINANCIAL
RESOURCES TO EXPLORATION OF PROPERTIES WHICH DO NOT CONTAIN ANY PROVEN RESERVES.
IN ADDITION, OUR OPERATIONS MAY BE AFFECTED BY SIGNIFICANT OPERATING HAZARDS AND
NATURAL DISASTERS.
We face a number of risks inherent in oil and gas exploration and development.
Exploration activities are expensive and consume significant financial
resources. Although we try to allocate our limited financial resources to those
properties which we believe are most likely to yield a discovery, we can never
be certain that our exploration activities on a particular property will be
successful. Like other oil and gas exploration companies, we try to mitigate our
exploration risk by conducting our activities jointly with other exploration
companies through joint ventures and farm-in/farm-out arrangements. In carrying
out our exploration activities, we are also vulnerable to adverse weather
conditions, mechanical difficulties, delays in the delivery of equipment and the
risk of fire, explosions and blow-outs.
WE ARE NOT ABLE TO GUARANTEE THE SUCCESSFUL COMMERCIAL DEVELOPMENT OF THE GTL
TECHNOLOGY.
No commercial-scale GTL plants have yet been constructed using Syntroleum's
proprietary GTL process and, therefore, the process has not been proven on a
commercial scale. Other commercial developers of GTL technology include
ExxonMobil, 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. The planned Sweetwater GTL plant requires
significant project financing in order to come into production on schedule in
2003. See Items 1 and 2. "Business and Properties -- Gas-to-Liquids Projects".
OUR OPERATIONS ARE AFFECTED BY THE VOLATILITY OF PRICES FOR CRUDE OIL AND
NATURAL GAS.
As with most other companies involved in resource exploration, we may be
adversely affected by future increases in the costs of conducting exploration,
development and resource extraction which may not be fully offset by increases
in the price received on sale of the crude oil or natural gas.
Our revenues, profitability and future growth, if any, and the value of our oil
and gas properties are substantially dependent on prevailing prices of oil and
gas. Our ability to borrow and to obtain additional capital on attractive terms
is also substantially dependent upon oil and gas prices. Prices for oil and gas
are subject to large fluctuations in response to relatively minor changes in the
supply of, and demand for, oil and gas, market uncertainty and a variety of
additional factors beyond our control. These factors include economic conditions
in the United States and Canada, the actions of the Organization of Petroleum
Exporting Countries, governmental regulation, political stability in the Middle
East and elsewhere, the foreign supply of oil and gas, the price of foreign
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of oil and gas would have an adverse effect on the
value of our properties, our financing capacity and our prospects for commencing
and sustaining any economic commercial production.
Over the last 10 years, oil prices have fluctuated from $10 to over $30 per
barrel. During 2000 and the first quarter of 2001, oil prices have remained in
the range of between $25 and $35 per barrel after experiencing a significant
decline to a low of approximately $10 per barrel in 1997 due to the Asian
financial crisis and other economic factors. Oil and gas prices could be
significantly impacted if the Kyoto Protocol is enacted. The Kyoto Protocol
requires Western countries, including the United States and Canada, to reduce
the emission of hydrocarbons to below existing levels, increase the efficiency
of the use of oil and its by-products and reduce consumption. In the long term,
we expect oil prices to remain volatile.
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
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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 CHINA AND OTHER FOREIGN COUNTRIES MAY LIMIT OUR
ACTIVITIES AND ADVERSELY AFFECT OUR BUSINESS OPERATIONS. THE INTERPRETATION AND
ENFORCEMENT OF OUR CONTRACTUAL RIGHTS MAY BE AFFECTED BY THE PREVAILING LAWS OF
THE FOREIGN JURISDICTION.
We hold our interests in our China properties through production sharing
contracts with CNPC. We also have two memoranda of understanding with CNPC's
subsidiary, PetroChina, indicating a mutual intention to negotiate additional
production sharing contracts. 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 cannot assure you, based on our existing memoranda of understanding with
PetroChina, that we will successfully negotiate additional production sharing
contracts. Although we enjoy a good relationship with CNPC in respect of our
existing production sharing contracts, it is possible that disputes between us
could arise in the future which must be resolved under foreign law. Foreign
legal mechanisms for resolving legal and business disputes are not necessarily
comparable to typical dispute resolution mechanisms used in Western countries.
In China, previously decided cases are not necessarily binding in subsequent
disputes, meaning that outcomes tend to be unpredictable. 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.
THE COST OF COMPLYING WITH GOVERNMENTAL REGULATIONS IN THE UNITED STATES AND
CHINA MAY ADVERSELY AFFECT OUR BUSINESS OPERATIONS.
We are subject to various federal, state, provincial and local government
regulations in the United States and China. These regulations may change
depending on prevailing political or economic conditions. In order to comply
with these regulations, we may be required to obtain discharge permits for
drilling operations, post-drilling and abandonment bonds and file reports
concerning our operations. These regulations affect how we carry on our business
and in order to comply with them we may incur increased costs and delay certain
activities pending receipt or requisite permits and approvals. If we fail to
comply with applicable regulations and requirements we may become subject to
enforcement actions, including orders issued by regulatory or judicial
authorities requiring us to cease or curtail our operations, take corrective
measures involving capital expenditures, installation of additional equipment,
or remedial actions. We may be required to compensate third parties for loss or
damage suffered by reason of our activities, and may face civil or criminal
fines or penalties imposed for violations of applicable laws or regulations.
Amendments to current laws, regulations and permits governing our operations and
activities could affect us in a materially adverse way and could force us to
increase expenditures or abandon or delay the development of new oil and gas
properties.
OUR BUSINESS OPERATIONS MAY BE ADVERSELY AFFECTED BY PRESENT OR FUTURE
ENVIRONMENTAL REGULATIONS.
Oil and gas exploration, development and production operations are subject to
varying degrees of environmental regulation in both China and the United States.
Environmental legislation is evolving in a manner which imposes stricter
standards and enforcement, increased fines and penalties for
28
29
non-compliance, more stringent environmental assessments of proposed projects
and a heightened degree of responsibility for companies and their officers,
directors and employees. Future changes in environmental regulation may
adversely affect our operations in unanticipated ways. Environmental hazards may
exist on the properties in which we currently hold interests, which are unknown
to us at present, caused by previous or existing owners or operators of the
properties.
Natural resource development projects in China are subject to periodic
environmental evaluation. While these evaluations have in the past generally not
resulted in substantial limitations on development activities, we expect that
they will become increasingly strict in the future. Moreover, environmental
awareness on the part of the public has been increasing, as has public pressure
on environmental authorities. The growing environmental concerns of the public
and an active environmental lobby may cause the Chinese government to impose
more extensive environmental liabilities.
We are committed to carrying out our oil and gas exploration and development
activities in accordance with generally accepted international environmental
standards. However, our compliance with current or future environmental laws in
China, the United States and elsewhere may have a material adverse effect on our
business and the liabilities resulting from any environmental damage caused by
our activities may be material. To the best of our knowledge, we are currently
operating in compliance with all applicable environmental regulations.
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.
IF WE LOSE OUR KEY MANAGEMENT AND TECHNICAL PERSONNEL, OUR BUSINESS MAY BE
ADVERSELY AFFECTED.
In carrying out our operations we rely upon a relatively small group of key
management and technical personnel. Messrs. David Martin, Leon Daniel and John
Carver, in particular, have extensive experience in oil and gas operations
throughout the world. 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 be
detrimental to our business.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are an oil and gas exploration and development company that currently has
limited production. Until June, 1999, we had a successful producing project in
Russia, but legal actions initiated in the Russian courts by our Russian joint
venture partner deprived us of the right to operate the field and to realize any
continuing return on our investment. As a result, we sold our interest in the
project in August, 2000. See Item 3. "Legal Proceedings". Oil and gas revenue
reported before 2000 was generated from our share of production from the Russian
project. We have exploration and development projects in California, Texas and
China. Our projects are at various stages and, like all exploration companies in
the oil and gas industry, we are exposed to the significant risk that our
exploration activities will not necessarily result in a discovery of
economically extractable reserves.
We currently have limited production exposed to commodity price risks. We are
exposed to the risk that we will be unable to engage competent cost-effective
contractors and suppliers for our operations, risks that damage to, or
malfunction of, our equipment will hinder our ability to carry out our
exploration activities and risks that foreign laws may not adequately protect
our interests in disputes with foreign partners and others.
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30
In the international petroleum industry, most production is bought and sold in
United States currency or with reference to United States currency. Accordingly,
we do not expect to face foreign exchange risks if and when we commence large
scale commercial production. Most of our business transactions are conducted in
United States currency in the countries in which we operate.
We currently have minimal debt obligations and, therefore, we do not believe
that we face any undue financial risk from interest rate fluctuations and we are
not currently involved in any transactions of a hedging nature.
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31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND RELATED INFORMATION
PAGE
-----
AUDITORS' REPORT............................................ 32
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets............................... 33
Consolidated Statements of Income and Deficit............. 34
Consolidated Statements of Cash Flow...................... 35
Notes to the Consolidated Financial Statements............ 36
SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION
ACTIVITIES (UNAUDITED).................................... 55
31
32
AUDITORS' REPORT
To the Shareholders of
IVANHOE ENERGY INC.:
We have audited the consolidated balance sheets of Ivanhoe Energy Inc. as at
December 31, 2000 and 1999 and the consolidated statements of income and deficit
and cash flow for each of the years in the three year period ended December 31,
2000. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
With respect to the consolidated financial statements for the year ended
December 31, 2000 we conducted our audit in accordance with Canadian generally
accepted auditing standards, and United States generally accepted auditing
standards. With respect to the consolidated financial statements for each of the
years in the two year period ended December 31, 1999, we conducted our audit in
accordance with Canadian generally accepted auditing standards. Those standards
require that we plan and perform an audit to obtain reasonable assurance whether
the financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31, 2000
and 1999 and the results of its operations and its cash flows for each of the
years in the three year period ended December 31, 2000 in accordance with
Canadian generally accepted accounting principles.
Calgary, Alberta (signed) Deloitte & Touche LLP
February 23, 2001 Chartered Accountants
COMMENTS BY AUDITORS FOR U.S. READERS ON
CANADA - U.S. REPORTING DIFFERENCES
In the United States of America, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph) outlining
changes in accounting principles that have been implemented in the financial
statements. As discussed in Note 10 to the financial statements, in 2000 the
Company changed its method of accounting for income taxes to conform to the new
Canadian Institute of Chartered Accountants Handbook recommendations Section
3465.
Calgary, Alberta (signed) Deloitte & Touche LLP
February 23, 2001 Chartered Accountants
32
33
IVANHOE ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(STATED IN THOUSANDS OF U.S. DOLLARS)
AS AT DECEMBER 31,
------------------
2000 1999
------- -------
ASSETS
Current Assets
Cash........................................................ $29,694 $ 2,637
Accounts receivable......................................... 4,532 1,349
Notes receivable -- current................................. 325 250
Deposits.................................................... 333 137
Prepaid expenses and advances............................... 214 188
------- -------
35,098 4,561
Deposits -- long-term....................................... 192 233
Notes receivable............................................ 50 350
Investments in Russian projects (Note 4).................... -- 16,200
Oil and gas equipment held for sale......................... -- 3,265
Capital assets (Note 5)..................................... 64,460 23,050
------- -------
$99,800 $47,659
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities.................... $ 2,951 $ 4,967
Convertible debenture (Note 6).............................. 1,000 1,000
------- -------
3,951 5,967
------- -------
Provision for site restoration.............................. 11 --
------- -------
Shareholders' Equity
Share capital (Note 7)...................................... 98,211 49,494
Deficit..................................................... (2,373) (7,802)
------- -------
95,838 41,692
------- -------
$99,800 $47,659
======= =======
APPROVED BY THE BOARD:
(signed) David Martin (signed) Leon Daniel
Director Director
33
34
IVANHOE ENERGY INC.
CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT
(STATED IN THOUSANDS OF U.S. DOLLARS EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
-------- -------- ----------
(RESTATED)
(NOTE 10)
REVENUE
Petroleum revenue.......................................... $ 851 $ 5,460 $ 10,977
Operating revenue.......................................... -- 296 --
Interest income............................................ 990 454 1,775
Gain on sale of Russian projects (Note 4).................. 12,222 -- --
-------- -------- --------
14,063 6,210 12,752
-------- -------- --------
EXPENSES
Operating costs............................................ 787 4,219 8,327
Project identification costs............................... 3,732 1,735 614
General and administrative................................. 2,829 2,639 2,294
Russian litigation......................................... 860 1,134 --
Interest and financing charges............................. 29 91 49
Foreign exchange loss (gain)............................... 56 (37) (1,292)
Depletion and depreciation................................. 341 1,714 4,729
Asset write downs (Note 9)................................. -- 2,517 70,242
-------- -------- --------
8,634 14,012 84,963
-------- -------- --------
Income (loss) before income taxes.......................... 5,429 (7,802) (72,211)
-------- -------- --------
INCOME TAX RECOVERY
Current.................................................... -- -- 42
Future..................................................... -- -- 1,492
-------- -------- --------
-- -- 1,534
-------- -------- --------
NET INCOME (LOSS).......................................... 5,429 (7,802) (70,677)
Deficit, beginning of year................................. 7,802 74,455 3,778
Transfer of deficit to share capital (Note 7).............. -- (74,455) --
-------- -------- --------
Deficit, end of year....................................... $ 2,373 $ 7,802 $ 74,455
======== ======== ========
NET INCOME (LOSS) PER SHARE (NOTE 11)...................... $ 0.05 $ (0.08) $ (0.79)
======== ======== ========
WEIGHTED AVERAGE NUMBER OF SHARES (IN THOUSANDS) (NOTE
11)...................................................... 119,719 99,687 89,694
======== ======== ========
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35
IVANHOE ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOW
(STATED IN THOUSANDS OF U.S. DOLLARS)
YEAR ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
-------- -------- ----------
(RESTATED)
(NOTE 10)
OPERATING ACTIVITIES
Net income (loss)........................................... $ 5,429 $ (7,802) $(70,677)
Items not requiring use of cash
Gain on sale of Russian projects.......................... (12,222) -- --
Asset write downs (Note 9)................................ -- 2,517 70,242
Depletion and depreciation................................ 341 1,715 4,729
Other..................................................... 67 47 (1,457)
-------- -------- --------
(6,385) (3,523) 2,837
Changes in non-cash working capital items................... (5,448) (2,707) 1,906
-------- -------- --------
(11,833) (6,230) 4,743
-------- -------- --------
INVESTING ACTIVITIES
Expenditures on capital assets.............................. (40,827) (10,728) (30,058)
Proceeds on sale of Russian projects........................ 28,182 -- --
Cash recovered from Tura joint venture, net of costs........ 240 1,198 1,215
Proceeds on sale of (expenditures on) equipment............. 3,288 4,352 (9,080)
Proceeds on payment of note................................. 250 -- --
Decrease (increase) in long-term deposits................... 42 (63) --
Interim funding -- Sunwing Energy Ltd....................... -- (329) (1,591)
-------- -------- --------
(8,825) (5,570) (39,514)
-------- -------- --------
FINANCING ACTIVITIES
Shares issued on private placements (net)................... 38,598 -- --
Shares issued on exercise of warrants....................... 8,083
Shares issued on exercise of options........................ 1,034 735 --
Notes payable issued, assumed or repaid (net)............... -- -- (2,028)
Non-current amount payable.................................. -- -- 45
-------- -------- --------
47,715 735 (1,983)
-------- -------- --------
Increase (decrease) in cash for the year.................... 27,057 (11,065) (36,754)
Cash, beginning of year..................................... 2,637 13,702 50,456
-------- -------- --------
Cash, end of year........................................... $ 29,694 $ 2,637 $ 13,702
======== ======== ========
SUPPLEMENTARY INFORMATION REGARDING NON-CASH TRANSACTIONS
(NOTE 3)
INCLUDED IN THE ABOVE ARE THE FOLLOWING:
Taxes paid.................................................. $ 8 $ 199 $ 454
======== ======== ========
Interest paid............................................... $ 120 $ 86 $ 77
======== ======== ========
DECREASE (INCREASE) IN NON-CASH WORKING CAPITAL ITEMS
Accounts receivable......................................... $ (3,182) $ (673) $ 351
Note receivable............................................. (25) -- --
Crude oil inventory......................................... -- 584 (283)
Deposits.................................................... (196) 1,221 (1,358)
Prepaid expenses and advances............................... (27) 162 150
Accounts payable and accrued liabilities.................... (2,018) (4,001) 3,046
-------- -------- --------
$ (5,448) $ (2,707) $ 1,906
======== ======== ========
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36
IVANHOE ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(EXPRESSED IN U.S. DOLLARS WITH AMOUNTS IN TABLES BEING IN THOUSANDS, EXCEPT PER
SHARE DATA)
1. NATURE OF OPERATIONS
Ivanhoe Energy Inc., a Canadian company, and its subsidiaries are focused
internationally on three major strategies: 1) exploration and development of
hydrocarbons 2) enhanced oil recovery and 3) the application of gas-to-liquids
technology. Activities are currently carried out in Southern California, Texas
and China. The name of the Company was changed from Black Sea Energy Ltd. to
Ivanhoe Energy Inc. on June 24, 1999.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements have been prepared in accordance with
generally accepted accounting principles ("GAAP") in Canada. The consolidated
financial statements also conform in all material respects to United States
GAAP, except for the following matters for which details are provided in the
referenced notes: -- the price per share used to record the acquisition of
royalty interests (Note 3); -- reduction of the deficit as at December 31, 1998
(Note 7); -- net income (loss) per share calculation (Note 11) and additional
disclosures required under United States GAAP (Note 14).
The preparation of financial statements requires management to make estimates
and assumptions that affect the reported amounts and other disclosures in these
consolidated financial statements. Actual results may differ from those
estimates.
PRINCIPLES OF CONSOLIDATION
These consolidated financial statements include the accounts of Ivanhoe Energy
Inc. and its subsidiaries, all of which are wholly owned.
All inter-company transactions and balances have been eliminated for the
purposes of these consolidated financial statements.
FOREIGN CURRENCY TRANSLATION
The Company has adopted the U.S. Dollar as its functional currency since it is
the currency of the economic environments in which the Company and its
subsidiaries operate. Monetary assets and liabilities denominated in foreign
currencies are converted at the exchange rate in effect at the balance sheet
date and non-monetary assets and liabilities at the exchange rates in effect at
the time of acquisition or issue. Revenues and expenses are converted at rates
approximating exchange rates in effect at the time of the transactions. Exchange
gains or losses resulting from the translation of foreign currency amounts are
reflected in operations.
CASH
Cash includes short-term money market instruments with terms to maturity, at the
date of issue, not exceeding 90 days.
FINANCIAL INSTRUMENTS
The fair value of the Company's cash, accounts receivable, notes receivable,
accounts payable and accrued liabilities approximates the carrying values due to
the immediate or short-term maturity of these financial instruments.
The estimated fair value of the convertible debenture at December 31, 2000 is
approximately $1,790,000.
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37
DEPOSITS
Deposits are primarily comprised of drilling bonds associated with the Company's
California operations ($185,000) which earn interest at 6% and temporary
deposits relative to contracted work on the gas-to-liquids projects ($148,000).
OIL AND GAS EQUIPMENT HELD FOR SALE
Drilling and ancillary oil and gas equipment, originally purchased for the
Company's prior owned Russian operations, was being held for sale. At December
31, 2000, all equipment has been sold and proceeds of $1,367,000 are included in
accounts receivable. As at December 31, 1999, the equipment was recorded at
estimated net realizable value, which was less than cost.
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for oil and gas
operations whereby all exploration and development expenditures are capitalized
on a country-by-country cost centre basis. Such expenditures include land
acquisition costs, geological and geophysical expenses, carrying charges for
unproved properties, costs of drilling both productive and non-productive wells,
gathering and production facilities and equipment, and financing and
administrative costs related to capital projects. Proceeds from sales of oil and
gas properties are recorded as reductions of capitalized costs, unless such
amounts would significantly alter the rate of depreciation and depletion,
whereupon gains or losses would be recognized in income. Maintenance and repair
costs are expensed as incurred, while improvements and major renovations are
capitalized.
Costs of oil and gas properties accumulated within each cost centre, including a
provision for future development costs, are depleted using the unit of
production method based on estimated proved reserves. Significant development
projects and expenditures on exploration properties are excluded from the
depletion calculation until evaluated. These excluded costs are evaluated
periodically for impairment.
Depletable costs, accumulated in each cost centre, net of depletion provided,
future income taxes and accumulated site restoration costs, are compared
annually to the non-discounted estimated future net revenues from proved
reserves (based on year-end non-escalated prices), net of estimated
administration and carrying costs, and related production and income taxes
("ceiling test"). Any accumulated costs in excess of the calculated ceiling test
are charged to operations.
Given the uncertainties then surrounding the Company's Russian projects,
commencing in 1999, the costs previously accumulated and unamortized in the
non-depletable cost pool were transferred to the depletable pool and depletion
of these costs provided on the unit of production method. At June 30, 1999, the
carrying value of the Russian properties was transferred to Investment in
Russian Properties (see Note 4).
Royalties acquired are included in oil and gas properties and recorded at cost.
Royalty costs have been allocated to project areas and costs associated with
producing areas are being amortized on the unit of production method based on
estimated proved reserves.
PROVISION FOR FUTURE SITE RESTORATION
The Company has developed an estimate for future site restoration and
abandonment costs and is amortizing this estimate to operations using the
unit-of-production method based upon estimated proved reserves. The provision is
included with depletion and depreciation expense.
FURNITURE AND FIXTURES
Furniture and fixtures are stated at cost. Depreciation is provided on a
straight-line basis over the estimated useful life of the respective assets, at
rates ranging from three to ten years.
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PETROLEUM REVENUE
Sales of crude oil are recognized in the period in which the crude oil is
shipped to the customer.
INCOME (LOSS) PER SHARE
The income (loss) per share is computed on the basis of the weighted average
number of shares outstanding during each year. The potential exercise of the
options disclosed in Note 7 and conversion of the convertible debenture
disclosed in Note 6 do not have a material dilutive effect on the income (loss)
per share under Canadian GAAP.
INCOME TAXES
Effective January 1, 2000, the Company has adopted the new recommendations of
the Canadian Institute of Chartered Accountants with respect to future income
taxes. Under these recommendations, the Company utilizes the liability method of
accounting for future income taxes. Previously the Company has used the deferral
method of accounting for income taxes. This change has been applied
retroactively and the financial statements of the Company for the years ended
December 31, 1999 and 1998 have been restated (Note 10).
Under the liability method, future income taxes are recognized to reflect the
expected future tax consequences arising from tax loss carry-forwards and
temporary differences between the carrying value and the tax basis of the
Company's assets and liabilities.
STOCK BASED COMPENSATION PLAN
The Company has an Equity Incentive Plan which is described in Note 7. The
options are issued at market price and no compensation expenses are recognized
for this plan when stock options are issued to employees. Consideration paid by
employees on exercise of stock options is credited to share capital.
3. ACQUISITIONS
SUNWING ENERGY LTD.
On June 22, 1999, the shareholders approved a statutory arrangement whereby the
Company acquired all the issued and outstanding shares of Sunwing Energy
Ltd.("Sunwing"), a private Yukon holding corporation related through a common
major shareholder and director. Prior to the statutory arrangement, Sunwing was
the corporate parent of the Sunwing group of companies. As part of the statutory
arrangement, Sunwing was dissolved effective the close of business on June 30,
1999.
The transaction resulted in the issuance to the former shareholders of Sunwing
of 17,596,000 shares of the Company based on a share exchange ratio approved by
an independent committee of directors of each of the Company and Sunwing and
supported by valuations and fairness opinions by the independent financial
advisor of each company.
Under an interim Funding and Security Agreement dated December 11, 1998, the
Company advanced $1,920,000 ($1,591,000 advanced to December 31, 1998) of
non-interest bearing interim loan funding to Sunwing pending finalization of the
transaction. The interim funding provided during 1998 and 1999, and the shares
issued to consummate the transaction, comprise the aggregate purchase price.
The common shares of the Company issued to complete the acquisition were valued
at $0.30 per share, being the market value per share at the date the directors
of the respective companies approved the share exchange ratio.
DIATOM PETROLEUM INC.
On May 1, 1998, Diatom, an unrelated private Nevada corporation based in
Bakersfield, California, entered into an exploration agreement with Aera Energy
LLC ("Aera"), a limited liability company owned
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39
by Shell Oil Company and Mobil Corp. Under the exploration agreement, Diatom was
granted certain exclusive exploration rights, with the right to participate at a
minimum of 12.5% in prospects identified in an area of more than 250,000 acres
in the Southern San Joaquin Valley. The exploration agreement gave Diatom 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
until September 1, 2001.
The Company successfully negotiated a farm-in to Diatom's exploration
arrangements with Aera in 1998 and, subsequently, acquired all of the issued and
outstanding shares of Diatom, pursuant to an agreement dated June 18, 1999, in
exchange for 500,000 common shares of the Company valued at $1.14 per share,
being the market value per share at the date of the agreement.
OVERRIDING ROYALTY
Pursuant to the terms of the Aera Exploration Agreement, Diatom has the right to
earn a 3.5% overriding royalty (the "Diatom Royalty") on production generated
from exploration activities. Prior to the Company's acquisition of Diatom, the
rights to the Diatom Royalty were subdivided as follows:
- a sub-royalty equal to three-sevenths of the Diatom Royalty was
allocated to the (now former) principals of Diatom and is known as the
"Founders' Royalty";
- a sub-royalty equal to two-sevenths of the Diatom Royalty was allocated
to a pool known as the "Common Royalty Pool" to be shared among the
consulting geologists and petroleum engineers retained on behalf of
Diatom to perform Diatom's exploration obligations under the Aera
Exploration Agreement; and
- a sub-royalty equal to two-sevenths of the Diatom Royalty was allocated
to a pool known as the "Finders' Royalty Pool" to be shared among those
consulting geologists and engineers carrying out analysis of technical
data leading to the identification of exploration prospects on the Aera
lands.
In October, 1999 the Company acquired a 50% interest in the Founders' Royalty,
together with a series of other overriding royalties which relate to lands in
the San Joaquin Valley not covered by the Aera Exploration Agreement, for
$860,000 and the issue of 1,562,000 common shares of the Company, at an ascribed
value per share of $2.02 (Cdn.$2.98), representing the market price per share at
the date of issue discounted to recognize a six month securities regulatory hold
period on the shares. The aggregate value of $4,023,000 has been capitalized.
See Note 5 "Capital Assets -- United States".
In March, 2000, the Company exercised an option it acquired in September 1999,
and issued 523,000 common shares to acquire a 37.5% interest in the Common
Royalty Pool. The ascribed value per share was $1.76 (Cdn.$2.55), representing
the market price per share at the date of issue, discounted to recognize the
securities regulatory hold period on the shares, for an aggregate value of
$917,000. Under an arrangement with Diatom, the members of the Common Royalty
Pool had the option of either increasing their percentage ownership in the
Common Royalty Pool, based on hours worked, or receiving remuneration from
Diatom for the hours worked, resulting in Diatom earning an interest in the
pool. At the date of the Company's acquisition of the 50% of the Common Royalty
Pool held by members other than Diatom, Diatom held a direct 25% interest in the
pool. This arrangement remains in effect and, to date, Diatom has acquired
additional interests of 0.072% of the Common Royalty Pool.
For United States GAAP purposes, the aggregate value attributed to the 1999
acquisition of the Founders' Royalty interest is $5,216,000, representing
1,562,000 common shares of the Company issued at $2.79 (the per share value at
the date the acquisition agreement was signed), and the $860,000 cash paid on
closing. The effect of this change for United States GAAP purposes is to
increase capital assets and share capital each by $1,193,000. For United States
GAAP purposes, the aggregate value attributed to the March, 2000 acquisition of
the Common Royalty Pool interest is $1,082,000, consisting of 523,000 shares
issued at $2.07 representing the market price per share at the date the
directors elected to exercise the option to acquire the interest. The effect of
this change for United States GAAP purposes is to increase capital assets and
share capital each by $165,000.
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40
At December 31, 2000, the Company in aggregate held a 1.437% overriding royalty
in production from lands covered by the Aera Exploration Agreement.
Subsequent to year end, the Company entered into an agreement to acquire
overriding royalties, ranging from 1.75% to 6.58%, in certain lands in the San
Joaquin Valley covered by the Aera Exploration Agreement. The aggregate purchase
price to be paid for these additional royalties is $3,950,000, being 800,000
shares at a value of $4.94 per share, being the market value per share at the
date of the signing of the purchase agreement.
NET ASSETS ACQUIRED AND CONSIDERATION PAID (CASH AND NON-CASH)
YEARS ENDED DECEMBER 31
----------------------------------------------------
2000 1999
---------- ---------------------------------------
OVERRIDING OVERRIDING
ROYALTIES SUNWING DIATOM ROYALTIES TOTAL
---------- ------- ------ ---------- -------
Investing activities, net assets acquired:
Petroleum properties........................ $917 $10,136 $548 $4,023 $14,707
Other long-term assets...................... -- 544 20 -- 564
Working capital (deficiency)................ -- (1,721) -- -- (1,721)
Convertible debenture assumed............... -- (1,000) -- -- (1,000)
---- ------- ---- ------ -------
917 7,959 568 4,023 12,550
Financing activities, non-cash:
Shares issued as consideration.............. 917 5,279 568 3,163 9,010
---- ------- ---- ------ -------
Cash consideration............................ $ -- $2,680 $ -- $ 860 $ 3,540
==== ======= ==== ====== =======
Comprised of:
Interim funding............................. $ -- $1,920 $ -- $ -- $ 1,920
Direct costs associated with acquisition.... -- 760 -- -- 760
Cash on closing............................. -- -- -- 860 860
---- ------- ---- ------ -------
$ -- $2,680 $ -- $ 860 $ 3,540
==== ======= ==== ====== =======
4. INVESTMENT IN RUSSIAN PROJECTS
The Company was initially incorporated to pursue energy opportunities in Russia
and, at one time, held three licenses to exploit oil and gas projects in Russia:
a 50% interest in an exploration and development project at the Kalchinskoye
field ("Tura") in western Siberia, a 50% interest in an exploration project at
the Radonezh field (a block adjacent to Tura and highly success-dependent on the
success of Tura) and, an enhanced oil recovery project in the Krasnodar region
near the Black Sea. The Krasnodar project was determined to be uneconomic and
was abandoned in 1998.
In May and June of 1998, the Company's Russian partner in its highly successful
producing Tura project, commenced a series of legal actions aimed at
invalidating the Tura license and gaining 100% control of the project. Although
the Company defended the actions vigorously in Russia and commenced
international arbitration proceedings in Stockholm, the Russian partner
prevailed in the Russian courts and took over control of Tura effective June 11,
1999.
For accounting purposes at December 31, 1998, the carrying value of all the
Company's Russian properties was written down by $46,724,000 through the
application of the ceiling test guidelines promulgated under GAAP. Based on the
Company's loss of control of the Tura project in June, 1999, effective June 30,
1999 operations of the Company's Russian projects ceased to be proportionately
consolidated and the carrying value of the investment in Russian projects was
again reviewed in relation to its then estimated net realizable value. No
further write-down was considered necessary.
In August, 2000, a negotiated settlement was reached resulting in the
disposition of the Russian properties, including the Radonezh project, for cash
proceeds of $28,182,000, net of $840,000 of
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settlement and severance costs. The proceeds exceeded the then carrying value of
the Company's investment in the Russian projects and the resulting gain of
$12,222,000 is included in income.
5. CAPITAL ASSETS
Capital assets categorized by geographic location are as follows:
CHINA USA TOTAL
------- ------- -------
DECEMBER 31, 2000
Oil and gas properties and equipment........................ $18,887 $32,349 $51,236
Less:
Accumulated depletion..................................... -- (254) (254)
------- ------- -------
18,887 32,095 50,982
------- ------- -------
Gas to Liquids
Master license............................................ -- 10,000 10,000
Equity investment in Sweetwater partnership............... -- 2,000 2,000
Other costs............................................... -- 1,253 1,253
------- ------- -------
-- 13,253 13,253
------- ------- -------
Furniture and fixtures...................................... -- 262 262
Less:
Accumulated depreciation.................................. -- (37) (37)
------- ------- -------
-- 225 225
------- ------- -------
$18,887 $45,573 $64,460
======= ======= =======
CHINA USA TOTAL
------- ------ -------
DECEMBER 31, 1999
Oil and gas properties and equipment........................ $13,245 $9,762 $23,007
Furniture and fixtures...................................... -- 37 137
Less:
Accumulated depreciation.................................. -- (4) (4)
------- ------ -------
-- 33 33
------- ------ -------
$13,245 $9,795 $23,040
======= ====== =======
In 1999, in addition to the above, there is $10,000 of net furniture and
fixtures in Canada that was fully depreciated in 2000.
YEARS ENDED DECEMBER 31
--------------------------
2000 1999 1998
------ ------ ------
DEPLETION AND DEPRECIATION
Charged to operations....................................... $ 330 $1,683 $4,664
Capitalized to property..................................... -- 39 203
Charged to inventory........................................ -- 172 1,204
------ ------ ------
$ 330 $1,894 $6,071
====== ====== ======
CAPITALIZED GENERAL AND ADMINISTRATIVE EXPENSES, RELATED
DIRECTLY TO ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES................................................ $1,549 $ 898 $ 722
====== ====== ======
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GAS-TO-LIQUIDS
During 2000, the Company acquired a master license from Syntroleum Corporation
permitting the Company to use Syntroleum's proprietary gas-to-liquid process
("GTL") in an unlimited number of GTL projects around the world except North
America, China and India. The Syntroleum process converts natural gas into
synthetic liquid hydrocarbons that can be utilized to develop, among other
things, cleaner-burning diesel fuel. The Company views the process as holding
significant potential for monetizing uneconomic stranded gas reserves in large
gas-prone regions of the world.
On October 5, 2000, the Company signed a letter of intent with Syntroleum to
acquire a 13% non-recourse partnership interest in Syntroleum's Sweetwater GTL
project under development in Western Australia. The plant, which will be located
on the Burrup Peninsula in Western Australia, will convert natural gas
contracted from the North West Shelf Venture Partners, to ultra-clean synthetic
specialty products such as lubricants, industrial fluids and paraffins as well
synthetic fuels. Under the terms of the letter of intent, the Company's 13%
interest will cost a total of $21,000,000, of which $2,000,000 has been paid and
will be used by Syntroleum, solely to fund front-end engineering and other
project development expenses. Payment of the remaining $19,000,000, is subject
to satisfaction of various conditions, including Syntroleum obtaining project
financing. The Company's participation does not require any further financial
commitments and entitles the Company to participate in 13% of the project cash
flow each year. The Sweetwater plant is currently scheduled for completion in
2003.
UNITED STATES
The Company has submitted 14 preliminary prospects to Aera (see Note 3
"Acquisitions -- Diatom Petroleum Inc.") and has thereby retained those areas as
exclusive areas for the Company to identify drillable prospects. Six drillable
prospects have been identified to date and submitted to Aera. Aera has elected
to participate in four of the prospects and, as a result, the Company will have
working interests in those prospects ranging from 12.5% to 47%. Aera will act as
operator for these prospects and drilling is expected to commence in late 2001
or 2002. In the two prospects where Aera has elected not to participate, the
Company will have a 100% working interest. In one of these prospects, South
Midway Sunset, the Company has drilled 21 wells during 2000 and commenced
commercial production during the third quarter of 2000.
The Company is continuing to identify prospects within the 14 preliminary
prospect areas and is working to develop other preliminary prospects in the
acreage covered by the Aera exploration agreement, as well as in other lease
acreage acquired by the Company in the Valley but not covered by the Aera
exploration agreement.
In 2000, the Company acquired a 62.5% (96.15% for the first four wells) working
interest in an exploration play in the Permian Basin in West Texas. Commercial
production also commenced on this acreage during the third quarter. Through a
series of transactions in late 2000 and early 2001 the Company acquired a
working interest in over 28,400 gross (20,700 net) acres in the Bossier trend in
East Texas, where drilling is expected to commence during the third quarter of
2001.
CHINA
The Company, through Sunwing, holds two production sharing contracts to develop
existing oil fields in the Daqing and Dagang regions of the People's Republic of
China. These two contracts entered into by Sunwing with the China National
Petroleum Corporation ("CNPC"), a state-owned company established under the laws
of the People's Republic of China, were approved by the Chinese Ministry of
Foreign Trade and Economic Cooperation on November 13, 1996 and November 13,
1997, respectively.
The contracts primarily take the form of production sharing agreements, whereby
the Company incurs 100% of the costs to earn approximately 82% of the
production, before recovery of costs incurred, reverting to a 49% share post
recovery. Value added tax of 5% is payable on oil produced from both projects
with a 2.5% priority production allocation to CNPC in the Daqing project. No
other royalties are
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payable with respect to oil production from the two projects provided that
annual gross production from the relevant project does not exceed 500,000
tonnes.
Each contract calls for the planning and completion of a pilot testing phase
followed by a full field development plan and implementation. The pilot program
is to assess the technological and economic viability of the project.
At Daqing, the pilot program was completed successfully in 1998. While the
decision was made to continue on to the field development plan, the Company
chose to delay the process and, by agreement, CNPC took over operatorship of the
field and the right to all revenue generated and responsibility for all costs
incurred. The field development plan was completed in 2000 and approved by the
relevant regulatory agencies in February 2001. Operatorship is expected to
revert back to the Company by the end of the first quarter in 2001.
At the Company's Dagang project, the pilot testing phase was completed in
February 2001. Nippon Oil Exploration Limited of Japan earned a 20% working
interest in the Company's interest in the project, by funding a disproportionate
share of the Dagang pilot testing expenditures. The decision has been made to
proceed with the preparation of the development plan for submission to CNPC
during the latter half of 2001. During the development plan preparation and
approval process the Company will continue operatorship of the Dagang project.
During the pilot testing phase, for accounting purposes, the results of
operations were credited to the project costs. With the evaluation stage now
completed and the decision made to enter the development and implementation
stage, all operating results will, in the future, be included in the Company's
consolidated statement of income. At Daqing, this will occur once the Company
assumes operatorship of the field.
6. CONVERTIBLE DEBENTURE
The $1,000,000 convertible debenture bears interest at U.S. prime plus 2.5%, is
due on the earlier of August 4, 2002 or within 90 days following written demand,
and is convertible into common shares (principal and interest, accrued and
unpaid, all or in part) of the Company at Cdn.$2.75 per share up to August 4,
2002.
7. SHARE CAPITAL
The authorized capital of the Company consists of an unlimited number of common
shares without par value and an unlimited number of preferred shares without par
value.
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The total number of issued and outstanding common shares is as follows:
NUMBER OF
COMMON SHARES AMOUNT
------------- --------
(THOUSANDS)
Balance December 31, 1997 and 1998.......................... 89,694 $114,157
Issued on exercise of options............................. 1,162 735
Issued for services....................................... 25 47
Issued on acquisition of
Sunwing Energy Ltd. (Note 3)........................... 17,596 5,279
Diatom Petroleum Inc. (Note 3)......................... 500 568
Overriding royalties (Note 3).......................... 1,562 3,163
Reduction of stated capital............................... -- (74,455)
------- --------
Balance December 31, 1999................................... 110,539 49,494
Issued for Private Placements, net........................ 11,250 38,598
Issued on exercise of warrants............................ 2,998 8,083
Issued on exercise of options............................. 1,545 1,034
Issued on acquisition of Consultants Royalty Management
(Note 3)............................................... 523 917
Issued for services....................................... 19 85
------- --------
Balance December 31, 2000................................... 126,874 $ 98,211
======= ========
The December 31, 2000 share dollar amount is net of a loan of $236,000 (December
31, 1999 -- $307,000) advanced to an employee to assist in the exercise of
incentive stock options as permitted under the Employees' and Directors' Equity
Incentive Plan.
PRIVATE PLACEMENTS AND SHARE PURCHASE WARRANTS
During 2000, the Company issued common shares under two private placements. In
January and February 2000, the Company issued 6,250,000 units, each unit
consisting of one common share and one share purchase warrant, for net proceeds
of $14,014,000. Each two warrants are exercisable into one common share at
Cdn.$4.00 until the first anniversary date of the private placement. At December
31, 2000, 255,000 of these warrants for the purchase of 127,500 common shares
remain unexercised. Subsequent to year end, the balance of these warrants were
exercised.
On October 17, 2000, the Company issued 5,000,000 units, each unit consisting of
one common share and one share purchase warrant, for net proceeds of
$24,584,000. Each two warrants are exercisable into one common share at $5.375
until the first anniversary date of the private placement. At December 31, 2000,
all of the warrants remain outstanding for purchase of 2,500,000 common shares.
REDUCTION OF STATED CAPITAL
The shareholders approved, on June 22, 1999, the reduction of stated capital in
respect of the common shares by an amount of $74,455,000 being equal to the
accumulated deficit as at December 31, 1998. Under United States GAAP, a
reduction of the deficit such as this is not recognized except in the case of a
quasi reorganization. The effect of this is that under United States GAAP, share
capital and deficit each are increased by $74,455,000 at December 31, 1999 and
2000.
EQUITY INCENTIVE PLAN
The Company has an Employees' and Directors' Equity Incentive Plan and under
this plan it grants, from time to time, stock options to directors, officers and
employees to purchase common shares at the quoted market value on the date of
the grant. These options are conditional on continuing employment and vest at
the discretion of the Board of Directors. Prior to 1999, all options granted
vested over a three year period and expired ten years from date of issue.
Options granted after March 1, 1999 were granted
44
45
on identical terms and vest over a five year period and expire five years from
date of issue. By shareholders resolution in 1998, the exercise price of the
options issued in 1997 were repriced from Cdn.$4.65 to Cdn.$1.75.
Following is a summary of the status of the Company's Equity Incentive Plan,
including changes during the years ended:
DECEMBER 31, 2000 DECEMBER 31, 1999 DECEMBER 31, 1998
------------------ ------------------ ------------------
WEIGHTED- WEIGHTED- WEIGHTED-
NUMBER AVERAGE NUMBER AVERAGE NUMBER AVERAGE
OF EXERCISE OF EXERCISE OF EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ --------- ------ --------- ------ ---------
(000'S) (CDN.$) (000'S) (CDN.$) (000'S) (CDN.$)
Outstanding at beginning of
period....................... 7,800 $1.18 8,090 $0.93 3,385 $1.75
Granted........................ 1,991 6.39 2,065 2.56 7,300 0.70
Exercised...................... (1,545) 1.17 (1,162) 1.33 -- --
Cancelled/forfeited............ (85) 3.00 (1,193) 1.75 (2,595) 1.35
------ ----- ------ ----- ------ -----
Outstanding at end of period... 8,161 $2.45 7,800 $1.18 8,090 $0.93
====== ===== ====== ===== ====== =====
Options exercisable at period
end.......................... 5,356 $1.24 4,328 $0.92 3,560 $1.13
====== ===== ====== ===== ====== =====
The following table summarizes information respecting stock options outstanding
at December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------- ------------------------------
WEIGHTED AVERAGE
RANGE OF NUMBER REMAINING WEIGHTED AVERAGE NUMBER WEIGHTED AVERAGE
EXERCISE PRICES OUTSTANDING CONTRACTUAL LIFE EXERCISE PRICE EXERCISABLE EXERCISE PRICE
- - --------------- ----------- ---------------- ---------------- ----------- ----------------
(CDN.$) (000'S) (CDN.$) (000'S) (CDN.$)
$0.50 to $1.75....... 4,500 7.9 years $0.61 4,466 $0.61
$2.50 to $3.40....... 1,670 4.0 years $2.69 491 $2.75
$6.13 to $7.62....... 1,991 5.0 years $6.39 398 $6.39
----- --------- ----- ----- -----
$0.50 to $7.62....... 8,161 6.4 years $2.45 5,356 $1.24
===== ========= ===== ===== =====
Subsequent to December 31, 2000, the following options were exercised: 2,500 at
Cdn.$1.75, 10,000 at Cdn.$1.01 and 33,333 at Cdn.$0.50. In addition, 100,000
options were granted at Cdn.$7.53.
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8. SEGMENT INFORMATION
Geographic segment results from operations for the years ended December 31,
2000, 1999 and 1998 are detailed below.
YEAR ENDED DECEMBER 31, 2000
-------------------------------------
CANADA CHINA USA TOTAL
------- ------- ------- -------
Petroleum revenue..................................... $ -- $ -- $ 851 $ 851
Other revenue......................................... 197 8 785 990
------- ------- ------- -------
197 8 1,636 1,841
------- ------- ------- -------
Operating costs....................................... -- -- 787 787
Project identification costs.......................... 3,732 -- -- 3,732
Capital taxes......................................... -- 1 -- 1
General and administration............................ 1,610 677 541 2,828
Interest and financing................................ -- 27 2 29
Depletion and depreciation............................ 10 31 300 341
Foreign exchange (gain) loss.......................... 56 -- -- 56
------- ------- ------- -------
5,408 736 1,630 7,774
------- ------- ------- -------
Income (loss) for year................................ $(5,211) $ (728) $ 6 (5,933)
======= ======= =======
Gain on sale of Russian investments................... 12,222
Russian litigation costs.............................. (860)
-------
Net income............................................ $ 5,429
=======
Capital expenditures
Acquired for cash................................... $ -- $ 5,676 $35,151 $40,827
Acquired for shares................................. -- -- 917 917
------- ------- ------- -------
$ -- $ 5,676 $36,068 $41,744
======= ======= ======= =======
Identifiable assets................................... $ 7,342 $20,836 $71,622 $99,800
======= ======= ======= =======
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YEAR ENDED DECEMBER 31, 1999
-----------------------------------------------
RUSSIA CANADA CHINA USA TOTAL
------- ------- ------- ------- -------
Petroleum revenue................................ $ 5,460 $ -- $ -- $ -- $ 5,460
Operating revenue................................ 296 -- -- -- 296
Other revenue.................................... 55 393 1 5 454
------- ------- ------- ------- -------
5,811 393 1 5 6,210
------- ------- ------- ------- -------
Operating costs.................................. 4,219 -- -- -- 4,219
Project identification costs..................... -- 1,735 -- -- 1,735
Capital taxes.................................... -- 176 -- -- 176
General and administration....................... 210 1,152 923 178 2,463
Interest and financing........................... -- 72 19 -- 91
Russian litigation............................... -- 1,134 -- -- 1,134
Depletion and depreciation....................... 1,665 32 14 3 1,714
Foreign exchange (gain) loss..................... (61) 29 (5) -- (37)
Asset write downs................................ -- 2,437 -- -- 2,437
------- ------- ------- ------- -------
6,033 6,767 951 181 13,932
------- ------- ------- ------- -------
Loss for year.................................... $ (222) $(6,374) $ (950) $ (176) (7,722)
======= ======= ======= =======
Peru asset impairment............................ (80)
-------
Net loss......................................... $(7,802)
=======
Capital expenditures
Acquired for cash.............................. $ 1,283 $ 3 $ 3,532 $ 5,830 $10,648
Acquired for shares............................ -- -- 9,749 3,731 13,480
------- ------- ------- ------- -------
$ 1,283 $ 3 $13,281 $ 9,561 24,128
------- ------- -------
Peru -- cash................................... 80
-------
$24,208
=======
Identifiable assets.............................. $16,200 $ 6,784 $14,448 $10,227 $47,659
======= ======= ======= ======= =======
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YEAR ENDED DECEMBER 31, 1998
------------------------------
RUSSIA CANADA TOTAL
-------- -------- --------
Petroleum revenue........................................... $ 10,977 $ -- $ 10,977
Operating revenue........................................... 107 1,668 1,775
Other revenue............................................... -- -- --
-------- -------- --------
11,084 1,668 12,752
-------- -------- --------
Operating costs............................................. 8,327 -- 8,327
General and administration.................................. 450 1,811 2,261
Project identification costs................................ -- 614 614
Capital taxes............................................... -- 33 33
Interest and financing...................................... -- 49 49
Depletion and depreciation.................................. 4,645 84 4,729
Foreign exchange (gain) loss................................ (1,347) 55 (1,292)
Asset write downs........................................... 47,948 8,794 56,742
-------- -------- --------
60,023 11,440 71,463
-------- -------- --------
Income (loss)............................................... (48,939) (9,772) (58,711)
Income tax recovery......................................... 1,534 -- 1,534
-------- -------- --------
Income (loss) for year...................................... $(47,405) $ (9,772) $(57,177)
======== ========
Peru asset impairment....................................... (13,500)
--------
Net loss.................................................... $(70,677)
========
Capital expenditures
Acquired for cash......................................... $ 16,326 $ 4 $ 16,330
Equipment for sale........................................ -- 9,098 9,098
-------- -------- --------
$ 16,326 $ 9,102 25,428
======== ========
USA....................................................... 227
Peru...................................................... 13,500
--------
$ 39,155
========
Identifiable assets......................................... $ 21,203 $ 27,753 $ 48,956
======== ========
USA....................................................... 486
--------
$ 49,442
========
During 2000, three customers represented greater than 10% of total sales, being
44%, 40% and 12% respectively, for an aggregate of 96%.
During 1999, two customers represented greater than 10% of total sales, being
85% and 11% respectively, for an aggregate of 96%. In 1998, the Company derived
its revenue from various customers, four of which represent greater than 10% of
total sales. These four customers respectively represent 28%, 21%, 15% and 14%
of total sales, for an aggregate of 78%.
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9. ASSET WRITE-DOWNS
Asset write-downs include the following amounts:
YEAR ENDED
DECEMBER 31,
-------------------
1999 1998
------ -------
Ceiling test write-down of Russian properties (Note 4)...... $ -- $46,724
Provision for impairment of Peru costs...................... 80 13,500
Write down of oil and gas equipment to estimated net
realizable value.......................................... 2,437 8,794
Write down of crude oil inventory to estimated net
realizable value.......................................... 1,224
------ -------
$2,517 $70,242
====== =======
During 1998, the Company, through its wholly-owned U.S. subsidiary, entered into
an agreement with Pangaea International Ltd. ("Pangaea"), a Canadian private
company controlled by a major shareholder and director of the Company. Under the
agreement, the Company earned a 50% interest in Pangaea's Block 71, a 2.5
million acre hydrocarbon exploration and development concession located in the
Ucayali Basin in east central Peru, by incurring the cost associated with
completing the initial well. The Company's costs associated with the initial
well were estimated at approximately $13,500,000, an amount approximately equal
to what Pangaea had spent to date.
In December, 1998, the first well was drilled and while there were some minor
oil shows they were not deemed to be of economic significance and the well was
abandoned. The Company and Pangaea relinquished Block 71 during 2000.
10. INCOME TAXES
As described in Note 2, the Company has adopted the liability method of
accounting for income taxes retroactively and has restated its financial
statements. The effect of the restatement is to increase the deficit at the
beginning of the year ended December 31, 1998 by $929,000 to $3,778,000,
increase the recovery of future taxes for the year ended December 31, 1998 to
$1,492,000 and decrease the net loss for the year ended December 31, 1998 to
$70,677,000.
The accounting policy has not resulted in a change to the financial statements
of the Company for the year ended December 31, 1999. In addition, this change in
accounting policy does not result in a substantive change to the financial
position or the results of operations as at and for the year ended December 31,
2000. As a result of this change under Canadian GAAP, the Company's financial
statements are now also in compliance with United States GAAP with respect to
income taxes.
The Company and its subsidiaries are required to individually file tax returns
in each of the jurisdictions in which they operate. Details of the determination
of the actual income tax expense for each of the three years is detailed below.
For ease of presentation, the loss, as a result of the write down of Russian
assets, and the subsequent gain on settlement has been classified as Russian
operations, even though neither of these two items will have any tax effect in
Russia. The actual loss of approximately $35 million, being the aggregate
investment, ignoring accounting write downs, less proceeds received on
settlement will be a capital loss for Canadian income tax purposes, available
for carry-forward against future Canadian capital gains indefinitely.
In 1999 and 1998, expenditures incurred in Peru were made through the Company's
U.S. subsidiary, and as a consequence, are deductible in the U.S. For
determination of income tax expense (recovery), activities in Peru have been
combined with those in the U.S.
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50
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
------- ------- --------
Source income (loss) before income taxes.................... $ 5,429 $(7,802) $(72,211)
------- ------- --------
Composite statutory income tax rate......................... 43.20% 42.78% 37.20%
Expected income tax (recovery).............................. $ 2,345 $(3,338) $(26,866)
Non-deductible expenses for tax purposes.................... 78
Application of tax benefits not recognized previously....... (2)
Tax benefit of write-down (gain) of Russian assets not
recognized................................................ (4,908) 15,595
Tax benefit not recognized.................................. 2,565 3,260 9,737
------- ------- --------
Income tax expense.......................................... $ -- $ -- $ (1,534)
======= ======= ========
In 1999, concurrent with the loss of field operations in Russia, the Company
ceased proportionately consolidating the Russian results. The amounts displayed
above for 1999 are for the first six months of 1999 only.
The tax loss carry-forwards in Canada are Cdn. $27,049,000 and in the United
States $24,436,000. The tax losses carry-forward in Canada expire between 2003
and 2007, in the United States between 2018 and 2020. In China the Company has
available for carry-forward against future Chinese income $31,822,000 of cost
basis. Due to the uncertainty of utilizing these tax losses carry-forwards and
the benefit of deductible temporary differences, the Company has made a
valuation allowance of an equal amount against these potential recoverable
amounts as detailed below. The substantial increase in 1999 resulted from the
acquisition of Sunwing.
AS AT DECEMBER 31,
-------------------------------
2000 1999 1998
-------- -------- -------
Future tax assets........................................... $ 23,909 $ 23,439 $ 9,832
Valuation allowance......................................... (23,909) (23,439) (9,832)
-------- -------- -------
Net future tax liability.................................... $ -- $ -- $ --
======== ======== =======
11. NET INCOME (LOSS) PER SHARE
The Company, in connection with its initial public offering in June 1997, placed
in escrow 31,457,000 common shares held by certain shareholders, to be released
one-third per year on the succeeding three anniversary dates of the public
offering. For Canadian GAAP, as the release of shares from escrow is based on
time rather than on any performance criteria, these shares are considered issued
and outstanding and form part of the calculation of earnings and fully dilutive
earnings per share. Under United States GAAP, these escrow shares are considered
issued and outstanding only after they are released from escrow.
Under Canadian GAAP, fully diluted net income (loss) per share amounts are
calculated by applying the imputed earnings method to the stock options
outstanding in order to assess the dilutive impact. Under United States GAAP,
the net income (loss) per share amounts are calculated using the treasury method
in order to assess the dilutive impact of stock options.
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51
As a result, under United States GAAP the calculation of net income (loss) per
share is different from the calculation under Canadian GAAP. The relevant
amounts calculated under United States GAAP are as follows:
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- ------- -------
UNITED STATES GAAP
Net income (loss) per share................................. $ 0.05 $ (0.09) $ (1.10)
======== ======= =======
Weighted average number of shares (in thousands)............ 115,065 84,547 64,069
======== ======= =======
12. RELATED PARTY TRANSACTIONS
The Company has entered into agreements with a number of entities, some of which
are related through common directors or shareholders, to share administrative
personnel, office space and facilities. Costs are accumulated and the Company is
billed its proportionate share based on usage.
The costs incurred in the normal course of business with respect to the above
arrangements amounted to $1,581,000 for 2000; $1,692,000 for 1999, and
$1,004,000 for 1998. Included in accounts payable are amounts due under these
arrangements totaling $486,000 (1999 -- $953,000, 1998 -- $183,000)
respectively.
13. COMPARATIVE FIGURES
Certain of the comparative amounts have been reclassified to conform to the
presentation adopted for the current year.
14. ADDITIONAL DISCLOSURES REQUIRED UNDER UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES ("GAAP")
The Company's consolidated financial statements have been prepared in accordance
with GAAP as applied in Canada. In the case of the Company, Canadian GAAP
conforms in all material respects with United States GAAP, except for certain
matters which were mentioned in Note 2. Where these matters impact the financial
statements, the details of the differences are as follows:
CONSOLIDATED STATEMENTS OF INCOME
The application of United States GAAP would not have any effects on net income
as reported, except on Net Income (Loss) per share (Note 11).
The Company has no items which would be disclosed as other comprehensive income
under United States GAAP.
STOCK BASED COMPENSATION
In 1995, the United States Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, "Accounting for Stock-Based
Compensation." The Company has a stock-based compensation plan as more fully
described in Note 7. With regards to its stock option plan, the Company applies
APB Opinion No. 25, as interpreted by FASB ("FIN") 44, in accounting for this
plan and accordingly no compensation cost has been recognized. Had compensation
expense been determined based on fair value at the grant date for the stock
option grants consistent with the method
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of SFAS No. 123, the Company's net loss and net loss per share would have been
reduced to the pro forma amounts indicated below:
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
------ -------- --------
Net income (loss) under United States GAAP (thousands)...... $5,429 $ (7,802) $(70,677)
Pro forma (thousands)..................................... $3,289 $(11,840) $(72,012)
Net income (loss) per common share under United States
GAAP...................................................... $ 0.05 $ (0.08) $ (0.79)
Pro forma................................................. $ 0.03 $ (0.12) $ (0.80)
Stock options issued during period (thousands).............. 1,991 2,065 7,300
Weighted average exercise price............................. $ 4.29 $ 1.73 $ 0.36
Weighted average fair value of options granted during the
period.................................................... $ 2.32 $ 1.96 $ 0.24
Compensation cost (thousands)............................... $ -- $ -- $ --
The foregoing information is calculated in accordance with the Black-Scholes
option pricing model, using the following data and assumptions: volatility, as
of the date of grant, computed using the prior one to three-year weekly average
prices of the Company's common shares, which ranged from 59% to 108%; expected
dividend yield -- 0%; option terms to expiry -- 5 to 10 years as defined by the
option contracts; risk-free rate of return as of the date of grant -- 5.09% to
5.70%, based on five year Government of Canada Bond yields.
CONSOLIDATED BALANCE SHEETS
The application of United States GAAP would have the following effects on
balance sheet items as reported:
SHAREHOLDERS' EQUITY
Shareholders' equity at December 31, 1999 under Canadian
GAAP...................................................... $41,692
Adjustment to ascribed value of shares issued for royalty
interests (Note 3)........................................ 1,193
-------
Shareholders' equity at December 31, 1999 under United
States GAAP............................................... $42,885
=======
Shareholders' equity at December 31, 2000 under Canadian
GAAP...................................................... $95,838
Adjustment to ascribed value of shares issued for royalty
interests in 1999 (Note 3)................................ 1,193
Adjustment to ascribed value of shares issued for royalty
interests in 2000 (Note 3)................................ 165
-------
Shareholders' equity at December 31, 2000 under United
States GAAP............................................... $97,196
=======
Under United States GAAP, the transfer of deficit to share capital which
occurred during the year ended December 31, 1999 would not be recognized (Note
7). As a result, shareholders' equity under United States GAAP would comprise
the following:
AS AT DECEMBER 31,
--------------------
2000 1999
-------- --------
Share capital (including adjustments above)................. $174,024 $125,142
Deficit..................................................... (76,828) (82,257)
-------- --------
$ 97,196 $ 42,885
======== ========
CAPITAL ASSETS
There are certain differences between the full cost method of accounting for oil
and gas assets as applied in Canada and as applied in the United States. The
principal difference results in the method of performing ceiling test
evaluations under the full cost accounting rules. Under Canadian GAAP,
non-discounted future net revenues from oil and gas production, less an estimate
for future general and
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administrative expenses, financing costs and income taxes are compared to the
carrying value of the depletable petroleum properties, whereas for United States
GAAP future net revenues are discounted to present value at 10% per annum and
compared to the carrying value of the depletable petroleum properties. The
Company has performed the ceiling test in accordance with US GAAP and determined
that no material variances in financial statements balances would have resulted.
The Company capitalizes certain internal costs on the basis that they relate
directly to the acquisition, exploration and development activities and do not
include costs related to production, general corporate overhead, or similar
activities. Included in capital assets are the following capitalized internal
costs:
2000.............................. $1,549
1999.............................. $ 898
1998.............................. $ 722
The categories of costs included in the cost of oil and gas properties and
equipment, including the adjustments, in accordance with U.S. GAAP, to the
ascribed value of shares issued for royalty interests of $1,193,000 in 1999 and
$165,000 in 2000 (Note 3) are as follows:
AS AT AS AT AS AT
DECEMBER 31 DECEMBER 31 DECEMBER 31
2000 1999 1998
----------- ----------- -----------
Unproved properties................................ $26,180 $13,960 $ 25,735
GTL license, investment and other costs............ 13,253 -- --
Mineral interests in properties.................... 7,468 7,468 24,987
Wells and related production equipment and
facilities....................................... 18,946 2,771 35,307
Support equipment.................................. 368 174 2,230
------- ------- --------
66,215 24,373 88,259
Accumulated depletion and depreciation............. (397) (130) (68,517)
------- ------- --------
$65,818 $24,243 $ 19,742
======= ======= ========
The 1999 balances have been reduced by the reclassification of the net Russian
properties, as discussed in Note 2.
As at December 31, 2000 cost of unproved properties included in capital assets
are as follows:
INCURRED IN
--------------------------
TOTAL 2000 1999 1998
------- ------- ------- ----
Acquisition........................................... $10,268 $ 6,391 $ 3,878 $ --
Exploration........................................... 9,373 4,507 4,639 227
Royalty Rights........................................ 6,539 1,322 5,217 --
------- ------- ------- ----
$26,180 $12,220 $13,733 $227
======= ======= ======= ====
ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following is the breakdown of accounts payable and accrued liabilities:
AS AT AS AT
DECEMBER 31 DECEMBER 31
2000 1999
----------- -----------
Accounts payable............................................ $2,912 $4,957
Accrued liabilities......................................... 39 10
------ ------
Total....................................................... $2,951 $4,967
====== ======
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Significant accrual balances include:
AS AT
DECEMBER 31,
------------
2000 1999
---- ----
Salaries and related expenses............................... $ -- $ --
Income and other taxes...................................... $ -- $ --
Other general and administrative............................ $ 29 $ --
Interest.................................................... $ 10 $ 10
CONSOLIDATED STATEMENTS OF CASH FLOW
The application of United States GAAP would have no effect on the statements of
cash flow as reported.
IMPACT OF NEW AND PENDING U.S. GAAP ACCOUNTING STANDARDS
Statement of Financial Account Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133), was issued in June 1998, by the
Financial Accounting Standards Board. SFAS 133, as amended by SFAS 137 and 138,
establishes new accounting and reporting standards for derivative instruments
and for hedging activities. This statement requires an entity to establish, at
the inception of a hedge, the method it will use for assessing the effectiveness
of the hedging derivative and the measurement approach for determining the
ineffective aspect of the hedge. Those methods must be consistent with the
entity's approach to managing risk. SFAS 133 will be effective for the 2001
fiscal year. The Company has completed a preliminary assessment of the effect,
if any, that SFAS 133 will have on its consolidated balance sheet at December
31, 2000. prepared under U.S. GAAP. The only adjustment that would be required
on adoption of SFAS 133 relates to the fair value of the convertible debenture,
which at December 31, 2000 exceeds the book value by $790,000. This would
increase liabilities and deficit by $790,000 at January 1, 2001
In December 1999, the staff of the Securities and Exchange Commission released
Staff Accounting Bulletin (SAB 101), "Revenue Recognition", to provide guidance
on the recognition, presentation and disclosure of revenue in financial
statements. Management believes that its revenue recognition practices are in
conformity with SAB 101.
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SUPPLEMENTARY DISCLOSURES ABOUT OIL AND GAS PRODUCTION ACTIVITIES (UNAUDITED)
The following information about the Company's oil and gas producing activities
is presented in accordance with United States Statement of Financial Accounting
Standards No. 69: Disclosures About Oil and Gas Producing Activities.
OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic conditions.
Proved developed oil and gas reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Estimates of oil and gas reserves are subject to uncertainty and will change as
additional information regarding the producing fields and technology becomes
available and as future economic conditions change.
Reserves presented in this section represent the Company's working interest
share of reserves net of royalties. The reserves for 2000 in the U.S. are based
on estimates by the independent petroleum engineering firms of Duke Engineering
& Services and Joe C. Neal & Associates. In China, the reserves are based on
estimates by Gilbert Laustsen Jung Associates Ltd. The reserves in Russia at
December 31, 1998 are based on estimates by the independent petroleum
engineering firm, D&S Reservoir Engineering Ltd. The reserves presented for
December 31, 1999 represent reserves in China acquired through the acquisition
of Sunwing during 1999 and are based on estimates by the independent engineering
firm of Gilbert Laustsen Jung Associates Ltd.
The Company's net proved and net proved developed oil and gas reserves were as
follows:
OIL GAS
------- -------
(MBBL) (MMCF)
------- -------
Net proved reserves, December 31, 1997...................... 42,300
Kuban discontinued operations............................... (9,700)
Production.................................................. (1,823)
Revisions of previous estimates............................. (21,977)
-------
Net proved reserves, December 31, 1998...................... 8,800
Production.................................................. (807)
Loss of remaining reserves in Russia........................ (7,993)
Acquisition -- Sunwing...................................... 20,848
-------
Net proved reserves, December 31, 1999...................... 20,848
Extensions and discoveries.................................. 4,803 6,301
Production.................................................. (133) (5)
Revisions to previous estimates............................. 276
------- -------
Net proved reserves, December 31, 2000...................... 25,794 6,296
======= =======
Net Proved Developed Reserves
December 31, 1998......................................... 6,700 --
December 31, 1999......................................... -- --
December 31, 2000......................................... 1,573 984
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STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL AND GAS RESERVES
The following standardized measure of discounted future net cash flows from
proved oil and gas reserves has been computed using period end prices of $23.95
per barrel of oil ($22.95 per barrel in 1999 and $5.95 per barrel in 1998) and
$5.65 per Mcf of gas and costs and period end statutory tax rates. A discount
rate of 10% has been applied in determining the standardized measure of
discounted future net cash flows.
The Company does not believe that this information reflects the fair market
value of its oil and gas properties. Actual future net cash flows will differ
from the presented estimated future net cash flows in that:
- future production from proved reserves will differ from estimated
production;
- future production will also include production from probable and
potential reserves;
- future rather than year end prices and costs will apply; and
- existing economic, operating and regulatory conditions are subject to
change.
The standardized measure of discounted future net cash flows as at December 31
in each of the three most recently completed financial years are as follows:
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Future cash inflows........................................ $653,419 $469,260 $ 52,339
Future development and restoration costs................... 162,399 130,283 5,044
Future production costs.................................... 145,130 86,253 37,506
Future income taxes........................................ 102,831 79,878 2,859
-------- -------- --------
Future net cash flows...................................... 243,059 172,846 6,930
10% annual discount........................................ 141,823 101,736 1,747
-------- -------- --------
Standardized measure....................................... $101,236 $ 71,110 $ 5,183
======== ======== ========
Changes in standardized measure of discounted future net cash flows as at
December 31 in each of the three most recently completed financial years are as
follows:
2000 1999 1998
-------- -------- --------
Sale of oil & gas net of production costs.................. $ (64) $ (1,310) $ (2,924)
Revenue credited to China property costs................... (2,940) (92) --
Net changes in pricing and productions costs............... (3,433) 834 (42,622)
Purchase of reserves....................................... -- 71,202 --
Discoveries and extensions................................. 19,266 -- --
Abandonment of reserves.................................... -- (4,707) (7,912)
Revisions of previous estimates............................ 1,707 -- (16,061)
Net change in future development costs..................... 9,611 -- 22,899
Accretion of discount...................................... 5,979 -- 6,431
-------- -------- --------
Increase (decrease)........................................ 30,126 65,927 (40,189)
Standardized measure, beginning of year.................... 71,110 5,183 45,372
-------- -------- --------
Standardized measure, end of year.......................... $101,236 $ 71,110 $ 5,183
======== ======== ========
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COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES FOR THE FOLLOWING PERIODS ENDED:
YEAR ENDED
DECEMBER 31,
--------------------
2000 1999
------- -------
(IN THOUSANDS)
Property Acquisition
Proved.................................................... $ -- $ 7,468
Unproved.................................................. 6,392 3,878
Royalty rights............................................ 1,157 5,216
Development................................................. 16,436 4,086
Exploration................................................. 4,508 4,753
GTL license, investment and other costs..................... 13,252 --
------- -------
$41,745 $25,401
======= =======
Depletion, Depreciation and Amortization per unit of net production, before
write-down under ceiling test:
$/BOE
-----
RUSSIA
Year ended December 31, 1999................................ $3.04
Year ended December 31, 1998................................ $1.74
UNITED STATES
Year ended December 31, 2000................................ $8.70
RESULTS OF PRODUCING ACTIVITIES:
YEAR ENDED DECEMBER 31,
------------------------
2000 1999 1998
---- ----- -------
Sales....................................................... 851 5,460 10,977
Production expense.......................................... 787 4,150 8,053
Write-down of crude oil inventory........................... -- -- 1,224
Depletion (including write-down under ceiling test)......... 275 1,665 51,369
Other....................................................... -- (48) (730)
---- ----- -------
Income (loss) before income taxes........................... (211) (307) (48,939)
Income tax (recovery)....................................... -- -- (605)
---- ----- -------
Results of operations from producing activities............. (211) (307) (48,334)
==== ===== =======
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table provides the names of all of our directors and executive
officers, their positions, terms of office and their principal occupations
during the past five years. Each director is elected for a one year term or
until his successor has been duly elected or appointed. Officers serve at the
pleasure of the Board of Directors.
NAME, AGE AND POSITION WITH PRESENT OCCUPATION AND
MUNICIPALITY OF RESIDENCE THE REGISTRANT PRINCIPAL OCCUPATION FOR THE PAST FIVE YEARS
- - ------------------------- -------------- --------------------------------------------
DAVID MARTIN, age 69................... Chairman of the Board and Chairman of the Board of Ivanhoe Energy Inc.
Santa Barbara, California Director (since August, (August 1998 - present); President,
1998) Cathedral Mountain Corporation (1997 -
present); President and Chief Executive
Officer, Occidental Oil & Gas Corporation
(1986-1996); Executive Vice President and
Director, Occidental Petroleum Corporation
(1986-1996)
ROBERT M. FRIEDLAND, age 50............ Deputy Chairman (since Chairman and President, Ivanhoe Capital
Hong Kong June, 1999) and Director Corporation
(since February 1995)
E. LEON DANIEL, age 64................. President, Chief President and Chief Executive Officer of
Park City, Utah Executive Officer (since Ivanhoe Energy Inc. (June, 1999 - present);
June, 1999) and Director Executive Vice President, Worldwide Business
(since August, 1998) Development, Occidental Oil and Gas
Corporation (1996-1998); President,
Occidental Engineering Co. (1993-1996);
President, Worldwide Exploration, Occidental
Petroleum (1997-1998)
JOHN A. CARVER, age 68................. Director (since August, Retired (1998); Senior Vice President,
Bakersfield, California 1998) Worldwide Exploration, Occidental Petroleum
(1997-1998); Consultant (1996-1997);
Executive Vice President, Worldwide
Exploration, Occidental Oil and Gas
Corporation (1994-1996)
R. EDWARD FLOOD, age 55................ Director (since June, Mining Analyst, Haywood Securities (May,
Reno, Nevada 1999) 1999 - present); Deputy Chairman, Ivanhoe
Mines Inc. (May, 1999 - present); President,
Ivanhoe Mines Inc. (1995-1999); Member and
Gold Analyst of Contrarian Fund Management
Team of Robertson Stephens & Company
(1993-1995)
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NAME, AGE AND POSITION WITH PRESENT OCCUPATION AND
MUNICIPALITY OF RESIDENCE THE REGISTRANT PRINCIPAL OCCUPATION FOR THE PAST FIVE YEARS
- - ------------------------- -------------- --------------------------------------------
SHUN-ICHI SHIMIZU, age 60.............. Director (since July, Managing Director of C.U.E. Management
Tokyo, Japan 1999) Consulting Ltd. (1994 to present)
JOHN O'KEEFE, age 52................... Executive Vice-President, Executive Vice-President, Investor Relations
Houston, Texas Investor Relations and and Chief Financial Officer of Ivanhoe
Chief Financial Energy Inc. (September 2000 - present);
Officer (since September, Vice-President, Investor Relations of Santa
2000) Fe Snyder Corporation (1999 - September
2000); Director, Investor Relations of Oryx
Energy Company (1991-1999)
PATRICK CHUA, age 45................... Executive Vice-President Executive Vice-President of Ivanhoe Energy
Hong Kong, China (since June, 1999) Inc. (June, 1999 - present); Co-Chairman and
Director of Sunwing Energy Ltd. (June, 1996
-June, 1999); Co-Chairman and director,
Sunwing Energy Ltd. (BVI) (May, 1995 -
Present); prior thereto, Project Manager and
Senior Engineer, Sproule Associates Limited
GERALD MOENCH, age 55.................. Executive Vice-President Executive Vice-President of Ivanhoe Energy
Lethbridge, Alberta (since June, 1999) Inc. (June, 1999 - present); President and
Director, Sunwing Energy Ltd. (July, 1997 -
June, 1999); Acting President, Sunwing
Energy Ltd. (June, 1996 - July, 1997);
Consultant in Indonesia and New Zealand
(January, 1995 - June, 1996); prior thereto,
General Manager, Santos Petroleum (Seram)
Ltd.
BRADLEY C. SHOUP, age 42............... Executive Vice-President Executive Vice-President of Ivanhoe Energy
Dallas, Texas (since August, 1999) Inc. (August 1999 - present); Chief
Financial Officer of Ivanhoe Energy Inc.
(January, 2000 - September, 2000); Partner,
Relational Investors LLC (1996 - 1999);
Partner, Batchelder & Partners, Inc. (1988 -
1996)
Listed below are those of our directors who hold directorships in other publicly
listed corporations and the names of those corporations:
ROBERT M. FRIEDLAND: Ivanhoe Mines Ltd.
R. EDWARD FLOOD: Diamond Fields International Ltd., Emperor Mines Limited,
Ivanhoe Mines Ltd.
Each of our directors was elected at our last annual general meeting of
shareholders. The term of office of each director concludes at our next annual
general meeting of shareholders, unless the director's office is earlier vacated
in accordance with our by-laws. There are no family relationships among any of
our directors, officers or key employees.
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As required under the Business Corporations Act (Yukon), our Board of Directors
has an Audit Committee. We also have a Compensation and Benefits Committee. The
members of the Audit Committee are Messrs. Shun-Ichi Shimizu, Edward Flood and
John Carver. The members of the Compensation and Benefits Committee are Messrs.
David Martin, Edward Flood and Robert Friedland.
Based solely on a review of the reports furnished to us, we believe that during
2000 all of our directors, executive officers and 10% shareholders complied with
the applicable requirements for reporting initial ownership and changes in
ownership of our common shares.
ITEM 11. EXECUTIVE COMPENSATION
During the fiscal year ended December 31, 2000, we paid our executive officers
$873,000 in aggregate cash compensation. We do not provide any retirement
pension plan or retirement compensation agreement for our directors and
officers.
The following executive compensation disclosure relates to our President and
Chief Executive Officer as at December 31, 2000, and each of our four most
highly compensated executive officers (collectively, the "named executive
officers") whose annual compensation exceeded $100,000 in the year ended
December 31, 2000. During the year ended December 31, 2000, the total
compensation paid to those of our officers who received more than $100,000 in
total compensation was $886,182.
SUMMARY COMPENSATION
We paid the following compensation during the years ending December 31, 1998,
1999 and 2000 to each of our named executive officers.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG TERM COMPENSATION
----------------------------------- -------------------------------------
AWARDS PAYOUTS
--------------------------- ---------
SECURITIES
UNDER RESTRICTED
NAME AND OPTIONS/SARS SHARES OR LTIP ALL OTHER
PRINCIPAL SALARY BONUS OTHER ANNUAL GRANTED RESTRICTED PAYOUTS COMPENSATION
POSITION YEAR ($) ($) COMPENSATION (#) SHARE UNITS ($) ($)
- - -------- ---- --------- ------ ------------ ------------ ------------ ------- ------------
E. LEON DANIEL 2000 200,000 22,000 500,000
President & Chief 1999 148,580 1,144(6)
Executive 1998 500,000
Officer(1)
PATRICK CHUA 2000 180,000 4,711(6) 1,530
Executive Vice 1999 133,722 6,892(6) 500,000
President(2) 1998
BRADLEY C. SHOUP 2000 161,000 1,940(6)
Executive Vice 1999 300,000
President Corporate 1998
Development(3)
DAVID MARTIN 2000 50,000 110,000
Chairman(4) 1999
1998 4,000,000
GERALD MOENCH 2000 150,000 3,112(6) 745
Executive Vice 1999 111,435 4,583(6) 200,000
President(5) 1998
(1) Mr. E. Leon Daniel was appointed as our President and Chief Executive
Officer on June 22, 1999, and has been one of our directors since August
25, 1998.
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(2) Mr. Chua was appointed as an Executive Vice-President in June, 1999.
(3) Mr. Shoup has been an Executive Vice President since August, 1999. He was
also Chief Financial Officer from January to September, 2000.
(4) Mr. Martin has been our Chairman and one of our directors since August,
1998.
(5) Mr. Moench was appointed an Executive Vice-President in June, 1999.
(6) Includes premiums paid by us on behalf of the named executive officer for
medical, dental and other health insurance coverage.
OPTIONS AND STOCK APPRECIATION RIGHTS (SARS)
We granted the following Options/SARs to our named executive officers in the
financial year ended December 31, 2000:
OPTION/SAR GRANTS IN LAST FISCAL YEAR
PERCENT OF
NUMBER OF TOTAL
SECURITIES OPTIONS/SARS
UNDERLYING GRANTED TO
OPTIONS/SARS EMPLOYEES IN EXERCISE OF
GRANTED FISCAL BASE PRICE GRANT DATE
NAME (#) YEAR ($/SH) EXPIRATION DATE PRESENT VALUE $(1)
- - ---- ------------ ------------ ----------- --------------- ------------------
E. LEON DANIEL....... 500,000 25.558 $6.13 June 29, 2005 $6.13
(1) Equal to or greater than the weighted average price of our common shares on
The Toronto Stock Exchange for the five trading days preceding the date of
a grant.
AGGREGATED OPTION EXERCISES
The aggregate number of options exercised by any of the named executive officers
during the financial year ended December 31, 2000 was 766,666.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND
FINANCIAL YEAR END OPTION/SAR VALUES
NUMBER OF
UNDERLYING VALUE OF
SECURITIES UNEXERCISED
UNEXERCISED IN THE MONEY
OPTIONS/SARS OPTIONS/SARS
SHARES AT FY-END AT FY-END
ACQUIRED AGGREGATE (#) (CDN.$)
ON EXERCISE VALUE REALIZED EXERCISABLE/ EXERCISABLE/
NAME (#) ($) UNEXERCISABLE UNEXERCISABLE
- - ---- ------------ -------------- ------------- -------------
E. LEON DANIEL...................... 166,666 941,663 166,667/0 1,158,336/0
DAVID MARTIN........................ 600,000 3,765,000 3,400,000/0 23,630,000/0
PENSION PLANS
We do not presently provide a pension plan for our employees.
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EMPLOYMENT CONTRACTS, TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
We have no written employment contracts or termination of employment or change
of control arrangement with any of our directors or named executive officers.
DIRECTOR AND NAMED EXECUTIVE OFFICER COMPENSATION
We do not generally pay cash or other fixed compensation to our directors.
However, on a recommendation from the Compensation and Benefits Committee, the
Board awarded directors' fees to Mr. David Martin in the amount of $110,000, Mr.
E. Leon Daniel in the amount of $22,000 and Mr. John Carver in the amount of
$100,000. Also, as we call on the expertise of Mr. Carver beyond the ordinary
scope of his requirements as one of our directors, we will pay Mr. Carver a
supplemental director's fee of $30,000 per quarter. We reimburse our directors
for expenses they reasonably incur in the performance of their duties as
directors and they are also eligible to receive stock bonus awards from time to
time and to participate in our Employees' and Directors' Equity Incentive Plan.
The cash compensation we pay to the named executive officers is intended to be
comparable to the cash compensation paid to executive officers of similar
companies who have comparable duties and responsibilities.
EMPLOYEES' AND DIRECTORS' EQUITY INCENTIVE PLAN
Our Employees' and Directors' Equity Incentive Plan, as amended (the "Plan")
consists of three component plans: a common share option plan (the "Share Option
Plan"), a common share bonus plan (the "Share Bonus Plan"), and a common share
purchase plan (the "Share Purchase Plan"). The purpose of the Plan is to advance
our corporate interests, by encouraging equity participation by our directors,
officers and employees through the acquisition of our shares.
The following is a brief description of the terms of the Plan.
SHARE OPTION PLAN
The Share Option Plan allows the board of directors to grant options to acquire
our common shares in favour of our directors, officers and employees. Options
are subject to adjustment in the event of a subdivision or consolidation of our
common shares, an amalgamation, or other corporate event affecting our common
shares. Participation in the Share Option Plan is limited to directors, officers
and employees, who are, in the opinion of our board of directors, in a position
to contribute to our future growth and success.
In determining the number or value of optioned common shares made subject to
options, we consider the optionee's present and potential contribution to our
success and to the prevailing policies of each stock exchange on which our
shares are listed. The board of directors determines the date of grant, the
number of shares, the exercise price per share, the vesting period, and all
other terms and conditions of the options we grant. The minimum exercise price
of any option granted under the Share Option Plan is the weighted average price
of our common shares on the principal stock exchange on which our common shares
trade for the five trading days prior to the date of grant.
Unless earlier terminated upon an optionee's death or termination of employment
or appointment, options are exercisable for a period of up to ten years. We may,
in our discretion, accelerate unvested options if a take-over bid is made for
our common shares.
We may also grant share appreciation rights when we grant an option. Such rights
permit an optionee to elect to terminate the option and instead receive common
shares on the basis of a cashless exercise. The number of common shares that an
optionee who exercises share appreciation rights will receive is equal to the
difference between the then fair market value per common share and the option
price per common share of all common shares under option, divided by the then
fair market value per common share.
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SHARE BONUS PLAN
The Share Bonus Plan permits our board of directors to issue a maximum of
1,000,000 of our common shares as bonus awards to our directors and employees on
a discretionary basis having regard to such merit criteria as the board of
directors may determine.
SHARE PURCHASE PLAN
Participation in the Share Purchase Plan is limited to employees who have
completed at least one year (or less, at the discretion of the board of
directors) of continuous service on a full-time basis and who are designated by
the board of directors as eligible to participate in the Share Purchase Plan.
Eligible employees may contribute up to 10% of their annual basic salary to the
Share Purchase Plan in semi-monthly instalments. We then make contributions on a
quarterly basis equal to the employee's contribution.
At the end of each calendar quarter, the eligible employee receives a number of
our common shares equal to the aggregate amount contributed by the employee
participant and by us, on the participant's behalf, divided by the weighted
average trading price of our common shares on our principal stock exchange
during the previous three months.
The Share Purchase Plan component of the Plan has not yet been activated.
GENERAL
The aggregate maximum number of our common shares which we may issue or reserve
for issuance under the Plan is currently 12,000,000 common shares. Any increase
is subject to stock exchange approval and approval by our shareholders. The
maximum number of our common shares which we may, at any time, reserve for
issuance to any one person under the Plan may not exceed 5% of our issued and
outstanding common shares.
Our board of directors has the right to amend, modify or terminate our Equity
Incentive Plan. However, any amendment to the Equity Incentive Plan which would
materially increase the benefits under the Plan, materially modify the
requirements as to eligibility for participation in the Plan or materially
change the number of our common shares that may be issued or reserved for
issuance under the Plan, is subject to stock exchange approval and the approval
of our shareholders.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During the year ended December 31, 2000, our Compensation and Benefits Committee
consisted of Messrs. Robert Friedland, Edward Flood and David Martin. Mr. Martin
is one of our executive officers. Mr. Friedland is our largest shareholder and
holds interests in other entities with which we have transacted, and continue to
transact, business. See Item 13. "Certain Relationships and Related
Transactions."
BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Compensation and Benefits Committee administers our executive compensation
program, which is designed to provide incentives for our executive officers to
enhance shareholder value. Our principal objectives are to attract and retain
qualified executives critical to our success, to provide fair and competitive
compensation, to align their interests with those of our shareholders, and to
reward extraordinary corporate and individual performance on an annual basis. We
structure each compensation package in a manner that we believe links
shareholder return, measured by appreciation in share price,
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with executive compensation. Stock options are the primary mechanism we use to
align management and shareholder interests. We do not offer pension plans to our
senior executives.
Submitted on behalf of the Compensation Committee:
Mr. Robert Friedland
Mr. Edward Flood
Mr. David Martin
PERFORMANCE GRAPH
The following graph and table show changes since we completed our initial public
offering of common shares in June, 1997 and the value of $100 invested in our
common shares:
IVANHOE ENERGY INC. TSE 300 TOTAL RETURN INDEX
------------------- --------------------------
June 11, 1997 100 100
Dec. 31, 1997 38 104
Dec. 31, 1998 8 101
Dec. 31, 1999 58 131
Dec. 31, 2000 160 139
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Except as set forth below, no person or group is known to beneficially own (as
deemed by SEC Regulations) 5% or more of our issued and outstanding common
shares. Based on information known to us, the following table sets forth the
beneficial ownership of each such person or group in our common shares at March
1, 2001.
NAME AND ADDRESS OF NUMBER OF SHARES PERCENTAGE
TITLE OF CLASS BENEFICIAL OWNER BENEFICIALLY OWNED(1) OF CLASS
- - -------------- ------------------- --------------------- ----------
Common Shares Robert M. Friedland(2) 45,402,120 35.74%
Flat B, 31st Floor
Primrose Court
56A Conduit Road
Mid-Levels, Hong Kong
Common Shares Capital Research and Management Company 13,500,000(3) 10.45%
333 South Hope Street
Los Angeles, California
90071
Common Shares Paul Stephens 7,531,100 5.93%
388 Market Street
Suite 200
San Francisco, California
94111
Common shares RS Investment Management 7,963,624 6.27%
388 Market Street
Suite 200
San Francisco, California
94111
Common Shares Directors and Officers as a Group (11 53,376,710(4) 40.14%
persons)
- - ---------------
(1) Beneficial ownership is determined in accordance with the rules of the
Securities and Exchange Commission and generally includes voting or
investment power with respect to securities. Unissued common shares subject
to options, warrants or other convertible securities currently exercisable
or convertible, or exercisable or convertible within 60 days, are deemed
outstanding for the purpose of computing the beneficial ownership of common
shares of the person holding such convertible security but are not deemed
outstanding for computing the beneficial ownership of common shares of any
other person.
(2) 44,827,120 outstanding common shares are held indirectly through Newstar
Securities Ltd., Premier Mines Limited and Evershine LLC, companies
controlled by Mr. Friedland.
(3) Includes 2,500,000 common shares issuable upon exercise of share purchase
warrants.
(4) Includes 5,916,667 common shares issuable upon the exercise of incentive
stock options held by directors and officers as a group.
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SECURITY OWNERSHIP OF MANAGEMENT
The following table sets forth the beneficial ownership at March 1, 2001 of our
common shares by each of our directors, our named executive officers and by all
of our directors and executive officers as a group:
AMOUNT AND NATURE OF PERCENTAGE
TITLE OF CLASS NAME OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP OF CLASS
- - -------------- ------------------------ -------------------- ----------
Common Shares David Martin............................ 903,663 0.71
Common Shares Robert M. Friedland..................... 45,402,120 35.74
Common Shares E. Leon Daniel.......................... 502,018 0.40
Common Shares John A. Carver.......................... 195,000 0.15
Common Shares R. Edward Flood......................... 56,466 0.04
Common Shares Shun-ichi Shimizu....................... 32,500 0.03
Common Shares John O'Keefe............................ 25,000 0.02
Common Shares Patrick Chua............................ 275,776 0.22
Common Shares Gerald Moench........................... 5,000 --
Common Shares Bradley Shoup........................... 37,500 0.03
---------- -----
Common Shares All directors and executive officers as
a group (10 persons).................... 47,435,043 37.34%
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
TRANSACTIONS WITH MANAGEMENT AND OTHERS
We issued 3,220,000 of our common shares and an equal number of share purchase
warrants in February, 2000 to certain of our directors and executive officers as
part of a private placement of 6,250,000 common shares and share purchase
warrants. Units consisting of one common share and one share purchase warrant
were issued at a price of Cdn.$3.25 per unit. 4,000,000 units were purchased by
an arm's length institutional investor. The names of our directors and executive
officers and the number of securities each of them purchased are as follows:
NUMBER OF
COMMON SHARES
AND SHARE
PURCHASE WARRANTS
NAME (UNITS)
---- -----------------
Robert M. Friedland..................................... 1,985,000
David Martin............................................ 100,000
E. Leon Daniel.......................................... 10,000
John Carver............................................. 10,000
R. Edward Flood......................................... 30,000
Shun-ichi Shimizu....................................... 5,000
Patrick Chua............................................ 55,000
Bradley Shoup........................................... 25,000
CERTAIN BUSINESS RELATIONSHIPS
We are parties to cost sharing agreements with other companies in which Mr.
Robert M. Friedland has a material direct or indirect beneficial interest.
Through these agreements, we share office space, furnishings, equipment and
communications facilities in Vancouver, Singapore and London and an aircraft on
a cost recovery basis. We also share the costs of employing administrative and
non-executive management personnel at these offices. During the year ended
December 31, 2000, our share of these
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costs was $2,207,000. The companies with which we are parties to the cost
sharing agreements, and Mr. Friedland's ownership interest in each of them, are
as follows:
ROBERT FRIEDLAND
COMPANY NAME OWNERSHIP INTEREST
- - ------------ ------------------
Ivanhoe Mines Ltd....................................... 51.71%
Ivanhoe Capital Corporation............................. 100%
African Minerals Ltd.................................... 46%
Diamond Fields International Ltd........................ 7.85%
Pangaea Energy International Ltd........................ 72%
TABLE OF INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS
AND SENIOR OFFICERS
LARGEST AMOUNT
INVOLVEMENT OF OUTSTANDING DURING AMOUNT OUTSTANDING
NAME AND PRINCIPAL POSITION ISSUER OR SUBSIDIARY 2000 AS AT MARCH 1, 2001
- - --------------------------- -------------------- ------------------ -------------------
DAVID MARTIN..................... Loan Agreement $0.00 $201,629
Chairman
R. EDWARD FLOOD.................. Loan Agreement $0.00 $ 60,489
Director
We loaned Messrs. Martin and Flood the above-mentioned amounts in January, 2001
to facilitate their exercise of warrants to purchase 50,000 and 15,000 of our
common shares respectively. The loans bear interest at the Bank of Montreal
prime rate as quoted from time to time and the loans mature on January 26, 2002.
The loans are secured by a pledge of the 50,000 common shares owned by Mr.
Martin and the 15,000 common shares owned by Mr. Flood.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
The following financial statements and exhibits are filed as part of this Annual
Report:
(a) 1. FINANCIAL STATEMENTS:
Deloitte & Touche, LLP Auditors' Report on Consolidated Balance
Sheets of Ivanhoe Energy Inc. as at December 31, 2000 and 1999 and
Consolidated Statements of Loss and Deficit and Consolidated
Statements of Cash Flow of Ivanhoe Energy Inc. for the years ended
December 31, 2000, 1999 and 1998.
Consolidated Balance Sheets of Ivanhoe Energy Inc. as at December
31, 2000 and 1999.
Consolidated Statements of Loss and Deficit of Ivanhoe Energy Inc.
for the years ended December 31, 2000, 1999 and 1998.
Consolidated Statements of Cash Flow of Ivanhoe Energy Inc. for the
years ended December 31, 2000, 1999 and 1998.
Notes to the Consolidated Financial Statements of Ivanhoe Energy
Inc. for the years ended December 31, 2000, 1999 and 1998.
2. FINANCIAL STATEMENT SCHEDULES:
Supplementary Disclosures about Oil and Gas Production Activities
(Unaudited)
3. EXHIBITS
3.1 Articles of Ivanhoe Energy Inc. as amended to June 24, 1999
(incorporated by reference to Exhibits 1.1 through to 1.4 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).
3.2 Bylaws of Ivanhoe Energy Inc. (incorporated by reference to
Exhibit 1.1 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).
4.1 Amended and Restated Convertible Loan Agreement dated August
4, 1999 between Ivanhoe Energy Inc. and Linyi Holdings Ltd.
(incorporated by reference to Exhibit 3.2 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).
10.1 Funding and Participation Agreement dated August 1, 1998
between Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.) and Diatom Petroleum, Incorporated
(incorporated by reference to Exhibit 3.3 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).
10.2 Exploration Agreement dated May 1, 1998 between Diatom
Petroleum, Incorporated and Aera Energy LLC, as amended
January 18, 1999, March 29, 1999, September 15, 1999,
September 21, 1999 and April 5, 2000 (incorporated by
reference to Exhibit 3.4 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000).
10.3 Participation Agreement dated August 1, 1996 between Aera
Energy LLC (formerly CalResources, LLC), Digital
Petrophysics, Inc., Ivanhoe Energy (USA) Inc. (formerly West
Best Resources Ltd.) (as assignee of Texaco Exploration and
Production Inc.) and Wood Oil Company, as amended December
11, 1998 and further amended October 13, 1999 (incorporated
by reference to Exhibit 3.5 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000).
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10.4 Participation Agreement dated February 15, 1999 between Aera
Energy LLC, Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.), Diatom Petroleum, Inc. and Armstrong
Resources, LLC, as amended September 9, 1999 and further
amended November 15, 1999 (incorporated by reference to
Exhibit 3.9 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).
10.5 Diatom Petroleum, Incorporated Stock Purchase Agreement
dated June 18, 1999 between Ivanhoe Energy Inc. (formerly
Black Sea Energy Inc.), William R. Berry II, Deborah M.
Olson and Michael P. Stark, as amended July 2, 1999
(incorporated by reference to Exhibit 3.10 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000).
10.6 Digital Petrophysics Resources, Inc. Stock Purchase
Agreement dated September 3, 1999 between Ivanhoe Energy
(USA) Inc. and William R. Berry II and Deborah M. Olson
(incorporated by reference to Exhibit 3.11 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000).
10.7 Purchase Agreement for Sanford ORRI dated September 3, 1999
between Ivanhoe Energy (USA) Inc. and William R. Berry II
and Deborah M. Olson (incorporated by reference to Exhibit
3.12 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000).
10.8 Purchase Agreement for Founders' Royalty dated September 3,
1999 between Ivanhoe Energy (USA) Inc. and Michael P. Stark
(incorporated by reference to Exhibit 3.13 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000).
10.9 Option to Purchase Stock Agreement dated September 20, 1999
between Ivanhoe Energy (USA) Inc. and the shareholders of
Consultants Royalty Management, Inc. (incorporated by
reference to Exhibit 3.14 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000).
10.10 Farmout Agreement dated April 8, 1999 between Nippon Oil
Exploration Limited and Pan-China Resources Ltd., as amended
June 11, 1999 (incorporated by reference to Exhibit 3.16 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).
10.11 Petroleum Contract for Kongnan Block, Dagang Oilfield of the
People's Republic of China dated September 8, 1997 between
China National Petroleum Corporation and Pan-China Resources
Ltd., as amended June 11, 1999 (incorporated by reference to
Exhibit 3.15 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000).
10.12 Petroleum Contract for Zhou 13 Block in Zhao Zhou Oilfield,
Daqing, The People's Republic of China, dated August 8,
1996, between China National Petroleum Corporation and
Sunwing Energy Ltd. (incorporated by reference to Exhibit
3.17 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000).
10.13 Exploration Agreement dated October 1, 1999 between Prime
Natural Resources, LLC, Ivanhoe Energy (USA) Inc. and Aera
Energy LLC (incorporated by reference to Exhibit 3.23 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).
10.14 Service Agreement dated September 1, 1999 of CUE Management
Consultants Limited (incorporated by reference to Exhibit
3.31 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000).
10.15 Volume License Agreement dated April 26, 2000 between
Syntroleum Corporation and Ivanhoe Energy Inc. (incorporated
by reference to Exhibit 3.37 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000).
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10.16 Agreement dated May 11, 2000 between Discovery Operating,
Inc., Don L. Sparks and Ivanhoe Energy (USA) Inc.
(incorporated by reference to Exhibit 3.38 of Amendment No.
2 to Form 20-F filed with the Securities and Exchange
Commission on July 24, 2000).
10.17 Consultancy Agreement dated June 2, 2000 between Ivanhoe
Energy Inc. and M&A Oil Consultancy Limited (incorporated by
reference to Exhibit 3.39 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000).
10.18 Master License Agreement Amendment No. 1 dated October 11,
2000 between Syntroleum Corporation and Ivanhoe Energy Inc.
10.19 Consulting Agreement dated November 15, 2000 between Ivanhoe
Energy Inc. and Continental Energy Limited.
10.20 Employees' and Directors' Equity Incentive Plan.
10.21 Agreement for the Sale and Purchase of Shares in Great
Plains Petroleum (Cyprus) Limited and Global Petroleum
(Cyprus) Limited dated August 10, 2000 between Kuban
Petroleum Ltd., Ivanhoe Energy Inc. and Stesana Enterprises
Limited.
10.22 Deed of Release dated August 10, 2000 between Ivanhoe Energy
Inc., Kuban Petroleum Ltd., Tyumen Oil Company and
Tyumeneftegaz.
10.23 Agreement to Purchase shares of Digital Petrophysics, Inc.
dated January 26, 2001 between Ivanhoe Energy (USA) Inc.,
William R. Berry II and Deborah M. Olsen.
10.24 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Zitongxi and Zitongdong
Blocks.
10.25 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Yudong Block.
21.1 Subsidiaries of Ivanhoe Energy Inc.
23.1 Consent of D&S Reservoir Engineering Ltd., Petroleum
Engineers (incorporated by reference to Exhibit 3.34 of Form
20-F filed with the Securities and Exchange Commission on
February 28, 2000).
23.2 Consent of Gilbert Laustsen Jung Associates Ltd., Petroleum
Engineers.
23.3 Consent of Duke Engineering & Services.
23.4 Consent of Joe C. Neal & Associates.
(b) REPORTS ON FORM 8-K:
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
IVANHOE ENERGY INC.
By: /s/ E. LEON DANIEL
--------------------------------------
Name: E. Leon Daniel
Title: President and Chief Executive
Officer
Dated: March 16, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ E. LEON DANIEL President, Chief Executive Officer March 16, 2001
- - ----------------------------------- and Director
E. Leon Daniel (Principal Executive Officer)
/s/ JOHN O'KEEFE Executive Vice-President and Chief March 16, 2001
- - ----------------------------------- Financial Officer
John O'Keefe (Principal Financial and Accounting
Officer)
/s/ DAVID MARTIN Chairman of the Board and Director March 16, 2001
- - -----------------------------------
David Martin
/s/ ROBERT M. FRIEDLAND Deputy Chairman and Director March 16, 2001
- - -----------------------------------
Robert M. Friedland
/s/ JOHN A. CARVER Director March 16, 2001
- - -----------------------------------
John A. Carver
/s/ R. EDWARD FLOOD Director March 16, 2001
- - -----------------------------------
R. Edward Flood
/s/ SHUN-ICHI SHIMIZU Director March 16, 2001
- - -----------------------------------
Shun-ichi Shimizu
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EXHIBIT INDEX
EXHIBIT PAGE
- - ------- ----
3.1 Articles of Ivanhoe Energy Inc. as amended to June 24, 1999
(incorporated by reference to Exhibits 1.1 through to 1.4 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).......................................
3.2 Bylaws of Ivanhoe Energy Inc. (incorporated by reference to
Exhibit 1.1 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000)...................
4.1 Amended and Restated Convertible Loan Agreement dated August
4, 1999 between Ivanhoe Energy Inc. and Linyi Holdings Ltd.
(incorporated by reference to Exhibit 3.2 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).......................................................
10.1 Funding and Participation Agreement dated August 1, 1998
between Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.) and Diatom Petroleum, Incorporated
(incorporated by reference to Exhibit 3.3 of Form 20-F filed
with the Securities and Exchange Commission on February 28,
2000).......................................................
10.2 Exploration Agreement dated May 1, 1998 between Diatom
Petroleum, Incorporated and Aera Energy LLC, as amended
January 18, 1999, March 29, 1999, September 15, 1999,
September 21, 1999 and April 5, 2000 (incorporated by
reference to Exhibit 3.4 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000)....
10.3 Participation Agreement dated August 1, 1996 between Aera
Energy LLC (formerly CalResources, LLC), Digital
Petrophysics, Inc., Ivanhoe Energy (USA) Inc. (formerly West
Best Resources Ltd.) (as assignee of Texaco Exploration and
Production Inc.) and Wood Oil Company, as amended December
11, 1998 and further amended October 13, 1999 (incorporated
by reference to Exhibit 3.5 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000)....
10.4 Participation Agreement dated February 15, 1999 between Aera
Energy LLC, Ivanhoe Energy (USA) Inc. (formerly West Best
Resources Ltd.), Diatom Petroleum, Inc. and Armstrong
Resources, LLC, as amended September 9, 1999 and further
amended November 15, 1999 (incorporated by reference to
Exhibit 3.9 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000)...................
10.5 Diatom Petroleum, Incorporated Stock Purchase Agreement
dated June 18, 1999 between Ivanhoe Energy Inc. (formerly
Black Sea Energy Inc.), William R. Berry II, Deborah M.
Olson and Michael P. Stark, as amended July 2, 1999
(incorporated by reference to Exhibit 3.10 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000)..........................................
10.6 Digital Petrophysics Resources, Inc. Stock Purchase
Agreement dated September 3, 1999 between Ivanhoe Energy
(USA) Inc. and William R. Berry II and Deborah M. Olson
(incorporated by reference to Exhibit 3.11 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000)..........................................
10.7 Purchase Agreement for Sanford ORRI dated September 3, 1999
between Ivanhoe Energy (USA) Inc. and William R. Berry II
and Deborah M. Olson (incorporated by reference to Exhibit
3.12 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000)............................
10.8 Purchase Agreement for Founders' Royalty dated September 3,
1999 between Ivanhoe Energy (USA) Inc. and Michael P. Stark
(incorporated by reference to Exhibit 3.13 of Form 20-F
filed with the Securities and Exchange Commission on
February 28, 2000)..........................................
EI-1
73
EXHIBIT PAGE
- - ------- ----
10.9 Option to Purchase Stock Agreement dated September 20, 1999
between Ivanhoe Energy (USA) Inc. and the shareholders of
Consultants Royalty Management, Inc. (incorporated by
reference to Exhibit 3.14 of Form 20-F filed with the
Securities and Exchange Commission on February 28, 2000)....
10.10 Farmout Agreement dated April 8, 1999 between Nippon Oil
Exploration Limited and Pan-China Resources Ltd., as amended
June 11, 1999 (incorporated by reference to Exhibit 3.16 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).......................................
10.11 Petroleum Contract for Kongnan Block, Dagang Oilfield of the
People's Republic of China dated September 8, 1997 between
China National Petroleum Corporation and Pan-China Resources
Ltd., as amended June 11, 1999 (incorporated by reference to
Exhibit 3.15 of Form 20-F filed with the Securities and
Exchange Commission on February 28, 2000)...................
10.12 Petroleum Contract for Zhou 13 Block in Zhao Zhou Oilfield,
Daqing, The People's Republic of China, dated August 8,
1996, between China National Petroleum Corporation and
Sunwing Energy Ltd. (incorporated by reference to Exhibit
3.17 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000)............................
10.13 Exploration Agreement dated October 1, 1999 between Prime
Natural Resources, LLC, Ivanhoe Energy (USA) Inc. and Aera
Energy LLC (incorporated by reference to Exhibit 3.23 of
Form 20-F filed with the Securities and Exchange Commission
on February 28, 2000).......................................
10.14 Service Agreement dated September 1, 1999 of CUE Management
Consultants Limited (incorporated by reference to Exhibit
3.31 of Form 20-F filed with the Securities and Exchange
Commission on February 28, 2000)............................
10.15 Volume License Agreement dated April 26, 2000 between
Syntroleum Corporation and Ivanhoe Energy Inc. (incorporated
by reference to Exhibit 3.37 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000)...................................................
10.16 Agreement dated May 11, 2000 between Discovery Operating,
Inc., Don L. Sparks and Ivanhoe Energy (USA) Inc.
(incorporated by reference to Exhibit 3.38 of Amendment No.
2 to Form 20-F filed with the Securities and Exchange
Commission on July 24, 2000)................................
10.17 Consultancy Agreement dated June 2, 2000 between Ivanhoe
Energy Inc. and M&A Oil Consultancy Limited (incorporated by
reference to Exhibit 3.39 of Amendment No. 2 to Form 20-F
filed with the Securities and Exchange Commission on July
24, 2000)...................................................
10.18 Master License Agreement Amendment No. 1 dated October 11,
2000 between Syntroleum Corporation and Ivanhoe Energy
Inc......................................................... E-1
10.19 Consulting Agreement dated November 15, 2000 between Ivanhoe
Energy Inc. and Continental Energy Limited.................. E-7
10.20 Employees' and Directors' Equity Incentive Plan............. E-19
10.21 Agreement for the Sale and Purchase of Shares in Great
Plains Petroleum (Cyprus) Limited and Global Petroleum
(Cyprus) Limited dated August 10, 2000 between Kuban
Petroleum Ltd., Ivanhoe Energy Inc. and Stesana Enterprises
Limited..................................................... E-29
10.22 Deed of Release dated August 10, 2000 between Ivanhoe Energy
Inc., Kuban Petroleum Ltd., Tyumen Oil Company and
Tyumeneftegaz............................................... E-45
10.23 Agreement to Purchase shares of Digital Petrophysics, Inc.
dated January 26, 2001 between Ivanhoe Energy (USA) Inc.,
William R. Berry II and Deborah M. Olsen.................... E-52
10.24 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Zitongxi and Zitongdong
Blocks...................................................... E-57
EI-2
74
EXHIBIT PAGE
- - ------- ----
10.25 Memorandum of Understanding dated February 13, 2001 between
PetroChina Company Limited and Sunwing Energy Ltd. to
conduct a Joint Feasibility Study of Yudong Block........... E-60
21.1 Subsidiaries of Ivanhoe Energy Inc.......................... E-63
23.1 Consent of D&S Reservoir Engineering Ltd., Petroleum
Engineers (incorporated by reference to Exhibit 3.34 of Form
20-F filed with the Securities and Exchange Commission on
February 28, 2000)..........................................
23.2 Consent of Gilbert Laustsen Jung Associates Ltd., Petroleum
Engineers................................................... E-64
23.3 Consent of Duke Engineering & Services...................... E-65
23.4 Consent of Joe C. Neal & Associates......................... E-66
EI-3