Back to GetFilings.com
1
================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------------------
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
================================================================================
2
TABLE OF CONTENTS
PAGE
----
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
2
3
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.
3
4
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".
4
5
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
5
6
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
6
7
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
7
8
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.
8
9
- - - 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,
9
10
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
10
11
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
11
12
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
12
13
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
======= ======= =======
13
14
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.
14
15
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
15
16
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.
16
17
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
17
18
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)
18
19
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.
19
20
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.
20
21
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
21
22
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."
22
23
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
23
24
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
24
25
($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
======= ======= ======= =======
25
26
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.
26
27
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
27
28
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 c