EXHIBIT 1
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CANADIAN NATURAL RESOURCES LIMITED
ANNUAL INFORMATION FORM
March 30, 2005
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TABLE OF CONTENTS
DEFINITIONS....................................................................3
SPECIAL NOTE REGARDING FORWARD LOOKING STATEMENTS..............................4
THE COMPANY....................................................................6
GENERAL DEVELOPMENT OF THE BUSINESS............................................7
REGULATORY MATTERS.............................................................9
RISK FACTORS..................................................................10
ENVIRONMENTAL MATTERS.........................................................14
DESCRIPTION OF THE BUSINESS...................................................14
A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES.............................16
Drilling Activity..........................................................17
Producing Oil and Natural Gas Wells........................................18
Northeast British Columbia.................................................18
Northwest Alberta..........................................................20
Northern Plains............................................................21
Southern Plains and Southeast Saskatchewan.................................23
United Kingdom North Sea...................................................24
Offshore West Africa.......................................................25
Cote d'Ivoire..............................................................26
Angola.....................................................................26
Horizon Oil Sands Project..................................................27
B. CRUDE OIL AND NATURAL GAS RESERVES.........................................28
C. RECONCILIATION OF CHANGES IN NET RESERVES..................................33
D. OIL SANDS MINING RESERVES..................................................34
E. CRUDE OIL AND NATURAL GAS PRODUCTION.......................................34
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT....................................38
G. CAPITAL EXPENDITURES.......................................................39
H. NON-RESERVE ACREAGE........................................................41
I. DEVELOPED ACREAGE..........................................................41
SELECTED FINANCIAL INFORMATION................................................42
CAPITAL STRUCTURE.............................................................43
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MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................45
DIVIDEND HISTORY..............................................................46
TRANSFER AGENTS and REGISTRAR.................................................46
DIRECTORS AND EXECUTIVE OFFICERS..............................................47
AUDIT COMMITTEE INFORMATION...................................................51
LEGAL PROCEEDINGS.............................................................52
INTERESTS OF EXPERTS..........................................................52
ADDITIONAL INFORMATION........................................................52
SCHEDULE "A"..................................................................53
SCHEDULE "B"..................................................................56
CURRENCY
Unless otherwise indicated, all dollar figures stated in this Annual Information
Form represent Canadian dollars.
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DEFINITIONS
The following are definitions of selected abbreviations used in this Annual
Information Form:
"ARTC" means Alberta Royalty Tax Credit.
"bbl" or "barrel" means 34.972 Imperial gallons or 42 U.S. gallons.
"Bcf" means one billion cubic feet.
"bbls/d" means barrels per day.
"BOE" or "boe" means natural gas is converted to oil equivalent at the rate of
six thousand cubic feet equals one barrel of oil equivalent.
"Canadian Natural Resources Limited", "Canadian Natural", "CNRL" or "Company"
means Canadian Natural Resources Limited and includes, where applicable,
reference to subsidiaries of and partnership interests held by Canadian Natural
Resources Limited and its subsidiaries.
"FPSO" means floating production, storage and off-take vessel.
"gross acres" means the total number of acres in which the Company holds a
working interest or the right to earn a working interest.
"gross wells" means the total number of wells in which the Company has a working
interest.
"mbbl" means one thousand barrels.
"mcf" means one thousand cubic feet.
"mcf/d" means one thousand cubic feet per day.
"mmbbl" means one million barrels.
"mmbtu" means one million British thermal units.
"mmcf" means one million cubic feet.
"mmcf/d" means one million cubic feet per day.
"NGLs" means natural gas liquids.
"net acres" refers to gross acres multiplied by the percentage working interest
therein owned or to be owned by the Company.
"net wells" refers to gross wells multiplied by the percentage working interest
therein owned or to be owned by the Company.
"SAGD" means steam-assisted gravity drainage.
"undeveloped land" or "non-reserve acreage" refers to lands on which wells have
not been drilled or completed to a point that would permit the production of
commercial quantities of crude oil and natural gas.
"working interest" means the interest held by the Company in a crude oil or
natural gas property, which interest normally bears its proportionate share of
the costs of exploration, development, and operation as well as any royalties or
other production burdens.
"WTI" means West Texas Intermediate.
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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or incorporated herein by reference may
constitute "forward-looking statements" within the meaning of the United States
Private Litigation Reform Act of 1995. These forward-looking statements can
generally be identified as such because of the context of the statements
including words such as the Company "believes", "anticipates", "expects",
"plans", "estimates", or words of a similar nature.
The forward-looking statements are based on current expectations and are subject
to known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company, or industry results,
to be materially different from any future results, performance or achievements
expressed or implied by such forward-looking statements. Such factors include,
among others: the general economic and business conditions which will, among
other things, impact demand for and market prices of the Company's products; the
foreign currency exchange rates; the economic conditions in the countries and
regions in which the Company conducts business; the political uncertainty,
including actions of or against terrorists, insurgent groups or other conflict
including conflict between states; the industry capacity; the ability of the
Company to implement its business strategy, including exploration and
development activities; the impact of competition, availability and cost of
seismic, drilling and other equipment; the ability of the Company to complete
its capital programs; the ability of the Company to transport its products to
market; potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; the operating hazards and other
difficulties inherent in the exploration for and production and sale of oil and
natural gas; the availability and cost of financing; the success of exploration
and development activities; the timing and success of integrating the business
and operations of acquired companies; the production levels; the uncertainty of
reserve estimates; the actions by governmental authorities; the government
regulations and the expenditures required to comply with them (especially safety
and environmental laws and regulations); the site restoration costs; and other
circumstances affecting revenues and expenses. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such
factors are interdependent upon other factors, and management's course of action
would depend upon its assessment of the future considering all information then
available.
Statements relating to "reserves" are deemed to be forward-looking statements as
they involve the implied assessment based on certain estimates and assumptions
that the reserves described can be profitably produced in the future.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Although the Company believes that the expectations conveyed by the
forward-looking statements are reasonable based on information available to it
on the date such forward-looking statements are made, no assurances can be given
as to future results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable to the Company
or persons acting on its behalf are expressly qualified in their entirety by
these cautionary statements. The Company assumes no obligation to update
forward-looking statements should circumstances or management's estimates or
opinions change.
Special Note Regarding Currency, Production and Reserves
In this document, all references to dollars refer to Canadian dollars unless
otherwise stated. Reserves and production data is presented on a before
royalties basis unless otherwise stated. In addition, reference is made to oil
and natural gas in common units called barrel of oil equivalent ("boe"). A boe
is derived by converting six thousand cubic feet of natural gas to one barrel of
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crude oil (6mcf:1bbl). This conversion may be misleading, particularly if used
in isolation, since the 6mcf:1bbl ratio is based on an energy equivalency at the
burner tip and does not represent the value equivalency at the well head.
Canadian Natural retains qualified independent reserves evaluators to evaluate
the Company's proved and probable oil and natural gas reserves and prepare
Evaluation Reports on the Company's total reserves. Canadian Natural has been
granted an exemption from National Instrument 51-101 - Standards of Disclosure
for Oil and Gas Activities (NI 51-101) which prescribes the standards for the
preparation and disclosure of reserves and related information for companies
listed in Canada. This exemption allows the Company to substitute United States
Securities and Exchange Commission (SEC) requirements for certain disclosures
required under NI 51-101. The primary difference between the two standards is
the additional requirement under NI 51-101 to disclose proved and probable
reserves and future net revenues using forecast prices and costs. The Company
has disclosed proved reserves using constant prices and costs as mandated by the
SEC and has elected to provide proved plus probable reserves and values under
the same parameters as well as proved and proved plus probable reserves using
forecast prices and costs as additional voluntary information. Another
difference between the two standards is in the definition of proved reserves. As
discussed in the Canadian Oil and Gas Evaluation Handbook (COGEH), the standards
which NI 51-101 employs, the difference in estimated proved reserves based on
constant pricing and costs between the two standards is not material. The Board
of Directors of the Company has a Reserves Committee, which has met with each of
the Company's third party reserve evaluators and carried out independent due
diligence procedures with them as to the Company's reserves.
Reserves and net asset values presented for years prior to 2003 were evaluated
in accordance with the standards of National Policy 2-B which has now been
replaced by NI 51-101. The stated reserves were reasonably evaluated as
economically productive using year-end costs and prices escalated at appropriate
rates throughout the productive life of the properties.
Horizon oil sands mining reserves have been evaluated under SEC Industry Guide
7. Resource potential as determined for thermal oil assets and other potential
mining leases are determined using generally accepted industry methodologies for
resource delineation based upon stratigraphic well drilling completed on the
properties.
Special Note Regarding non-GAAP Financial Measures
Management's discussion and analysis includes references to financial measures
commonly used in the oil and gas industry, such as cash flow, cash flow per
share and EBITDA (net earnings before interest, taxes, depreciation depletion
and amortization, asset retirement obligation accretion, unrealized foreign
exchange, stock-based compensation expense and unrealized risk management
activity). These financial measures are not defined by generally accepted
accounting principles ("GAAP") and therefore are referred to as non-GAAP
measures. The non-GAAP measures used by the Company may not be comparable to
similar measures presented by other companies. The Company uses these non-GAAP
measures to evaluate the performance of the Company and of its business
segments. The non-GAAP measures should not be considered an alternative to or
more meaningful than net earnings, as determined in accordance with Canadian
GAAP, as an indication of the Company's performance.
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THE COMPANY
Canadian Natural Resources Limited was incorporated under the laws of the
Province of British Columbia on November 7, 1973 as AEX Minerals Corporation
(N.P.L.) and on December 5, 1975 changed its name to Canadian Natural Resources
Limited. CNRL was continued under the Companies Act of Alberta on January 6,
1982 and was further continued under the Business Corporations Act (Alberta) on
November 6, 1985. The head, principal and registered office of the Company is
located in Calgary, Alberta, Canada at 2500, 855 - 2nd Street S.W., T2P 4J8.
CNRL formed a wholly owned subsidiary, CanNat Resources Inc. ("CanNat") in
January 1995. Pursuant to a Plan of Arrangement, the Company acquired all of the
outstanding shares of Sceptre Resources Limited ("Sceptre") in September 1996
and in January 1997, Sceptre and CanNat amalgamated pursuant to the Business
Corporations Act (Alberta) under the name CanNat Resources Inc.
Pursuant to an Offer to Purchase all of the outstanding shares, the Company
completed the acquisition of Ranger Oil Limited, including its subsidiaries,
("Ranger") in July 2000. On October 1, 2000 Ranger and the Company amalgamated
pursuant to the Business Corporations Act (Alberta) under the name Canadian
Natural Resources Limited.
Pursuant to a Plan of Arrangement, the Company acquired all of the outstanding
shares of Rio Alto Exploration Ltd. ("RAX") in July 2002. On January 1, 2003 RAX
and the Company amalgamated pursuant to the Business Corporations Act (Alberta)
under the name Canadian Natural Resources Limited.
On January 1, 2004 CanNat and the Company amalgamated pursuant to the Business
Corporations Act (Alberta) under the name Canadian Natural Resources Limited.
The material operating subsidiaries of the Company, each of which is directly or
indirectly wholly-owned, and their jurisdiction of incorporation are as follows:
Name of Company Jurisdiction of Incorporation
- --------------- -----------------------------
CNR (ECHO) Resources Inc. Alberta
CNR International (U. K.) Investments Limited England
CNR International (U. K.) Limited England
CNR International Cote d'Ivoire SARL Cote d'Ivoire
Renata Resources Inc. Alberta
CNRL as the managing partner and CNR (ECHO) Resources Inc. and Renata Resources
Inc. are the partners of Canadian Natural Resources, a general partnership.
Canadian Natural Resources as the managing partner and Renata Resources Inc. and
CNRL are partners of Canadian Natural Resources Northern Alberta Partnership, a
general partnership. The two partnerships hold the Canadian crude oil and
natural gas properties of CNRL. CNRL also has a 15 per cent interest in Cold
Lake Pipeline Ltd., which is the general partner of Cold Lake Pipeline Limited
Partnership of which CNRL has a 14.7 per cent interest. CNRL as the managing
partner and Renata Resources Inc. are the partners of Canadian Natural Resources
2005 Partnership, a general partnership which holds certain natural gas
facilities situated in Alberta.
The consolidated financial statements of CNRL include the accounts of the
Company and all of its subsidiaries and partnerships.
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GENERAL DEVELOPMENT OF THE BUSINESS
CNRL's business is the acquisition of interests in crude oil and natural gas
rights and the exploration, development, production, marketing and sale of crude
oil and natural gas.
The Company initiates, operates and maintains a large working interest in a
majority of the prospects in which it participates. CNRL's objective is to
increase cash flow and earnings through the development of its existing crude
oil and natural gas properties and through the discovery and acquisition of new
reserves. The Company's principal regions of crude oil and natural gas
operations are in the Western Canadian Sedimentary Basin, the United Kingdom
(the "UK") sector of the North Sea and Offshore West Africa. The Company has a
full complement of management, technical and support staff to pursue these
objectives. As at December 31, 2004 the Company had 2,137 full time employees in
North America and 273 full time employees in its international operations.
On July 24, 2001, the Company issued US $400.0 million of 10 year 6.70 per cent
unsecured notes maturing July 15, 2011 pursuant to a prospectus supplement dated
July 19, 2001 to the short form shelf prospectus dated July 6, 2001. Pursuant to
a prospectus supplement dated January 15, 2002 to the short form shelf
prospectus dated July 6, 2001, the Company issued on January 23, 2002, US $400.0
million of 30 year 7.20 per cent unsecured notes maturing January 15, 2032.
In July 2002, pursuant to the terms of a Plan of Arrangement, the Company
acquired 100 per cent of RAX. The total purchase price was $2,393.2 million,
comprised of $850.0 million in cash, $522.4 million attributable to the issue of
10,008,218 common shares of the Company, and the assumption of $936.3 million of
debt and $84.5 million of working capital deficiency. The acquisition provided
the Company with a new core region for natural gas exploration and exploitation
activities in Northwest Alberta. The RAX properties included approximately 2.9
million net acres of undeveloped lands and provided additional opportunities for
the Company to increase its production and reserves of natural gas and natural
gas liquids. The acquisition added additional production, which averaged 376
million cubic feet per day of natural gas and 11 thousand barrels per day of
crude oil and natural gas liquids during the second half of 2002 and 2-D and 3-D
seismic of 57,820 kilometres and 14,565 square kilometres respectively. Future
exploration and development projects will take advantage of the large
undeveloped land base, high quality seismic database information and excess
capacity within existing facilities. The acquisition solidified the Company as
the second largest producer of natural gas in Canada and the second largest
undeveloped landholder in western Canada.
During 2002, the Company completed 128 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $516.3 million. These properties are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. In addition, the Company
disposed of non-operated properties not located in the Company's core regions
for proceeds of $76.1 million.
On September 16, 2002, the Company issued US $350.0 million of 10 year 5.45 per
cent unsecured notes maturing October 1, 2012 and US $350.0 million of 31 year
6.45 per cent unsecured notes maturing June 30, 2033 pursuant to a prospectus
supplement dated September 9, 2002 to a short form shelf prospectus dated August
16, 2002.
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During 2003, the Company completed 111 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate expenditure of $355.3 million. These properties are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. In addition, the Company
disposed of non-operated properties not located in the Company's core regions
for proceeds of $19.3 million.
In February 2004, the Company completed the acquisition of certain resource
properties located in East Central Alberta and Saskatchewan (collectively known
as the Petrovera Partnership) for aggregate consideration of $701 million. In a
separate transaction, the Company sold specific resource properties in the
Petrovera Partnership, representing approximately one third of the total
acquisition, to another independent producer for proceeds of $234 million,
resulting in a net cost of $467 million for the retained properties. The net
production from the working interests at the time of the acquisition retained by
the Company was approximately 27.5 mbbl/d of heavy oil and 9 mmcf/d of natural
gas together with volumes associated with royalty interests of 1.2 mbbl/d of
heavy oil and 2 mmcf/d of natural gas. All of the retained properties are
situated in the Company's core region of Northern Plains.
In April 2004, the Company completed an acquisition of certain oil and natural
gas properties located in Northeast British Columbia and Northwest Alberta for
consideration of $280 million. The properties at the time of acquisition were
producing approximately 68 million cubic feet per day of natural gas and 200
barrels per day of light crude oil and natural gas liquids and contain over 415
thousand acres of developed and undeveloped land. The properties included a
further interest in the Ladyfern natural gas field. The portion of the Ladyfern
field included in the acquisition included production of approximately 50
million cubic feet per day of natural gas. As part of this acquisition, the
Company also acquired undeveloped acreage in the Foothills area of Alberta and
British Columbia. This area is characterized by large, undeveloped pools with
significant natural gas potential in deeper zones and will add a new exploration
base in the Alberta Foothills, complementing the Company's existing holdings and
production base in the British Columbia Foothills.
In the third quarter of 2004 the Company's wholly owned subsidiary, CNR
International (U.K.) Limited acquired certain oil and natural gas properties in
the central North Sea. The acquired properties comprise operated interests in
T-Block (Tiffany, Toni and Thelma fields) and B-Block (Balmoral, Stirling and
Glamis fields) together with associated production facilities and adjacent
exploration acreage.
On December 1, 2004 the Company issued US $350.0 million of 10 year 4.90 per
cent unsecured notes maturing December 1, 2014 and US $350.0 million of 30 year
5.85 per cent unsecured notes maturing February 1, 2035 pursuant to a short form
shelf prospectus dated May 8, 2003.
In December 2004, the Company acquired certain oil and natural gas properties
located in Alberta and British Columbia, for an aggregate cash consideration of
approximately $703 million, net of proceeds received from an agreement to
concurrently dispose of a portion of such properties for approximately $50
million and cash flows realized from the effective date of September 1, 2004. At
the time of the acquisition production from the properties acquired by Canadian
Natural, after the above noted disposition, was estimated at 105 million cubic
feet per day of natural gas and 7,500 barrels per day of light crude oil and
NGLs being approximately 25,000 barrels of oil equivalent of daily production on
a six to one basis. The acquisition included over 510,000 net acres of
undeveloped land. The vast majority of the acquired
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properties is located in the Company's core areas and extends its Northern
Plains core region into the light oil operating area of Dawson.
During 2004, the Company completed 109 transactions (including the four
acquisitions mentioned above) in the normal course to acquire additional
interests in crude oil and natural gas properties at an aggregate net
expenditure of $1.371 billion (excluding the Petrovera Partnership acquisition
described above). These properties are located in the Company's principal
operating regions and are comprised of producing and non-producing leases
together with related facilities. In addition, the Company disposed of
non-operated properties not located in the Company's core regions for proceeds
of $7 million.
In February 2005 the Board of Directors of the Company approved Phase 1 of the
Horizon Oil Sands Project. See below "Horizon Oil Sands Project".
REGULATORY MATTERS
The Company's business is subject to regulations generally established by
government legislation and governmental agencies. The regulations are summarized
in the following paragraphs.
Canada
The petroleum and natural gas industry in Canada operates under various
government legislation and regulations, which govern exploration, development,
production, refining, marketing, prevention of waste and other activities.
The Company's Canadian properties are located in Alberta, British Columbia,
Saskatchewan, Manitoba and the Northwest Territories. Most of these properties
are held under leases/licences obtained from the respective provincial or
federal governments, which give the holder the right to explore for and produce
crude oil and natural gas. The remainder of the properties is held under
freehold (private ownership) lands.
Conventional petroleum and natural gas leases issued by the provinces of
Alberta, Saskatchewan and Manitoba have a primary term from two to five years,
and British Columbia leases/licences presently have a term of up to ten years.
Those portions of the leases that are producing or are capable of producing at
the end of the primary term will "continue" for the productive life of the
lease.
The exploration licences in the Northwest Territories are administered by the
Federal Government and only grant the right to explore. They have initial terms
of four to five years. A Commercial Discovery Licence must be obtained in order
to produce crude oil and natural gas, which requires the approval of a
satisfactory development plan.
An oil sands permit and oil sands primary lease is issued for five and fifteen
years respectively. If the minimum level of evaluation of an oil sands permit is
attained, a primary oil sands lease will be issued out of the permit. A primary
oil sands lease is continued based on the minimum level of evaluation attained
on such lease. Continued primary oil sands leases that are designated as
"producing" will continue for their productive lives while those designated as
"non-producing" can be continued by payment of escalating rentals.
The provincial governments regulate the production of crude oil and natural gas
as well as the removal of natural gas and natural gas liquids from each
province. Government royalties are payable on crude oil and natural gas
production from leases owned by the province. The
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royalties are determined by regulation and are generally calculated as a
percentage of production varied by a number of different factors including
selling prices, production levels, recovery methods, transportation and
processing costs, location and date of discovery.
The Company is subject to federal and provincial income taxes in Canada at a
combined rate of approximately 39.3 per cent after allowable deductions.
United Kingdom
Under existing law, the UK Government has broad authority to regulate the
petroleum industry, including the power to regulate exploration, development,
conservation and rates of production.
Crude oil and natural gas fields granted development approval before March 16,
1993 are subject to UK Petroleum Revenue Tax ("PRT") of 50 per cent charged on
crude oil and natural gas profits. Crude oil and natural gas fields granted
development approval on or after March 16, 1993 are exempted from PRT. Profits
for PRT purposes are calculated on a field-by-field basis by deducting field
operating costs and field development costs from production and third party
tariff revenue. In addition, certain statutory allowances are available, which
may reduce the PRT payable.
The Company is subject to UK Corporation Tax ("CT") on its UK profits as
adjusted for CT purposes. PRT paid is a deductible for CT purposes. The current
CT rate, which became effective April 1, 1999, is 30 per cent.
On April 17, 2002, the UK Government, in its 2002 budget speech by the UK
Chancellor of the Exchequer, announced changes to taxation policies on UK North
Sea crude oil and natural gas production. A supplementary CT charge of 10 per
cent, charged on the same profits as calculated for 'normal' CT but excluding
any deduction for financing costs, was added to the current 30 per cent CT
charge. Also the deduction for expenditures on capital items was changed from 25
per cent per annum to 100 per cent in the year incurred.
Offshore West Africa
Terms of licences, including royalties and taxes payable on production or profit
sharing arrangements, vary by country and in some countries by concession within
each country. Development of the Espoir field on CI-26, and the Baobab Field on
CI-40, Cote d'Ivoire, is under the terms of a production sharing arrangement
that provides that tax or royalty payments to the Government are deemed to be
met from the Government's share of profit oil (See "Principal Crude Oil and
Natural Gas Properties - Offshore West Africa").
RISK FACTORS
Volatility of Oil and Natural Gas Prices
The Company's financial condition will be substantially dependent on, and highly
sensitive to, the prevailing prices of crude oil and natural gas. Fluctuations
in crude oil or natural gas prices could have a material adverse effect on its
operations and financial condition and the value and amount of its reserves.
Prices for crude oil and natural gas fluctuate in response to changes in the
supply of and demand for, crude oil and natural gas, market uncertainty and a
variety of additional factors beyond the Company's control. Oil prices are
determined by international supply and demand. Factors which affect crude oil
prices include the actions of the Organization of Petroleum Exporting Countries,
the condition of the Canadian, United States and Asian economies, government
regulation, political stability in the Middle East and elsewhere, the foreign
supply of oil, the price of foreign imports, the availability of alternate fuel
sources and
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weather conditions. Natural gas prices realized by the Company will be affected
primarily in North America by supply and demand, weather conditions and prices
of alternate sources of energy. Any substantial or extended decline in the
prices of crude oil or natural gas could result in a delay or cancellation of
existing or future drilling, development or construction programs or curtailment
in production at some properties or resulting unutilized long-term
transportation commitments, all of which could have a material adverse effect on
Canadian Natural's revenues, profitability and cash flows.
Canadian Natural conducts an annual assessment of the carrying value of its
assets in accordance with Canadian generally accepted accounting principles. If
oil and natural gas prices decline, the carrying value of the assets could be
subject to downward revisions, and earnings could be adversely affected.
Approximately 27 percent of the Company's 2004 production on a boe basis was
primary and thermal heavy oil. The market prices for this heavy oil differ from
the established market indices for light and medium grades of oil, due
principally to the higher transportation and refining costs associated with
heavy oil. As a result, the price received for heavy oil is generally lower than
the price for medium and light oil, and the production costs associated with
heavy oil are relatively higher than for lighter grades. Future differentials
are uncertain and any increase in the heavy oil differentials could have a
material adverse effect on the Company's business.
Environmental Risks
All phases of the oil and natural gas business are subject to environmental
regulation pursuant to a variety of Canadian, United States, United Kingdom,
European Union and other federal, provincial, state and municipal laws and
regulations, as well as international conventions (collectively, "environmental
legislation").
Environmental legislation imposes, among other things, restrictions, liabilities
and obligations in connection with the generation, handling, storage,
transportation, treatment and disposal of hazardous substances and waste and in
connection with spills, releases and emissions of various substances to the
environment. Environmental legislation also requires that wells, facility sites
and other properties associated with the Company's operations be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. In addition, certain types of operations, including exploration and
development projects and significant changes to certain existing projects, may
require the submission and approval of environmental impact assessments or
permit applications. Compliance with environmental legislation can require
significant expenditures and failure to comply with environmental legislation
may result in the imposition of fines and penalties. The costs of complying with
environmental legislation in the future may have a material adverse effect on
Canadian Natural's financial condition or results of operations.
Canadian Natural anticipates that changes in environmental legislation may
require, among other things, reductions in emissions to the air from its
operations which may result in increased capital expenditures. Future changes in
environmental legislation could occur and result in stricter standards and
enforcement, larger fines and liability, and increased capital expenditures and
operating costs, which could have a material adverse effect on the Company's
financial condition or results of operations.
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Need to Replace Reserves
Canadian Natural's future oil and natural gas reserves and production, and
therefore its cash flows and results of operations, are highly dependent upon
success in exploiting its current reserve base and acquiring or discovering
additional reserves. Without additions to reserves through exploration,
acquisition or development activities, the Company's reserves and production
will decline over time as reserves are depleted. The business of exploring for,
developing or acquiring reserves is capital intensive. To the extent the
Company's cash flows from operations are insufficient to fund capital
expenditures and external sources of capital become limited or unavailable, the
Company's ability to make the necessary capital investments to maintain and
expand its oil and natural gas reserves will be impaired. In addition, Canadian
Natural may be unable to find and develop or acquire additional reserves to
replace its oil and natural gas production at acceptable costs.
Competition in Energy Industry
The energy industry is highly competitive in all aspects, including the
exploration for, and the development of, new sources of supply, the construction
and operation of crude oil and natural gas pipelines and facilities, the
acquisition of oil and natural gas interests and the transportation and
marketing of crude oil, natural gas, natural gas liquids and electricity.
Canadian Natural will compete not only among participants in the energy
industry, but also between petroleum products and other energy sources. The
Company's competitors will include integrated oil and natural gas companies and
numerous other senior oil and natural gas companies, some of which may have
greater financial and other resources than the Company.
Other Business Risks
Other business risks include operational risks, the cost of capital available to
fund exploration and development programs, regulatory issues and taxation and
the requirements of new environmental laws and regulations. Exploring for,
producing and transporting petroleum substances involves many risks, which even
a combination of experience, knowledge and careful evaluation may not be able to
overcome. These activities are subject to a number of hazards which may result
in fires, explosions, spills, blow-outs or other unexpected or dangerous
conditions causing personal injury, property damage, environmental damage and
interruption of operations. Canadian Natural's liability, property and business
interruption insurance may not provide adequate coverage in certain unforeseen
circumstances.
Foreign Investments
The Company's foreign investments involve risks typically associated with
investments in developing countries such as uncertain political, economic, legal
and tax environments. These risks may include, among other things, currency
restrictions and exchange rate fluctuations, loss of revenue, property and
equipment as a result of hazards such as expropriation, nationalization, war,
insurrection and other political risks, risks of increases in taxes and
governmental royalties, renegotiation of contracts with governmental entities
and quasi-governmental agencies, changes in laws and policies governing
operations of foreign-based companies and other uncertainties arising out of
foreign government sovereignty over the Company's international operations. In
addition, if a dispute arises in its foreign operations, the Company may be
subject to the exclusive jurisdiction of foreign courts or may not be successful
in subjecting foreign persons to the jurisdiction of a court in the United
States or Canada.
13
Canadian Natural's private ownership of oil and natural gas properties in Canada
differs distinctly from its ownership interests in foreign oil and natural gas
properties. In some foreign countries in which the Company does and may do
business in the future, the state generally retains ownership of the minerals
and consequently retains control of, and in many cases participates in, the
exploration and production of reserves. Accordingly, operations outside of
Canada may be materially affected by host governments through royalty payments,
export taxes and regulations, surcharges, value added taxes, production bonuses
and other charges. In addition, changes in prices and costs of operations,
timing of production and other factors may affect estimates of oil and natural
gas reserve quantities and future net cash flows attributable to foreign
properties in a manner materially different than such changes would affect
estimates for Canadian properties. Agreements covering foreign oil and natural
gas operations also frequently contain provisions obligating the Company to
spend specified amounts on exploration and development or to perform certain
operations, or forfeit all or a portion of the acreage subject to the contract.
Uncertainty of Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of reserves,
including many factors beyond the Company's control. In general, estimates of
economically recoverable oil and natural gas reserves and the future net cash
flow therefrom are based upon a number of factors and assumptions made as of the
date on which the reserve estimates were determined, such as geological and
engineering estimates which have inherent uncertainties, the assumed effects of
regulation by governmental agencies and estimates of future commodity prices and
operating costs, all of which may vary considerably from actual results. All
such estimates are, to some degree, uncertain and classifications of reserves
are only attempts to define the degree of uncertainty involved. For these
reasons, estimates of the economically recoverable oil and natural gas reserves
attributable to any particular group of properties, the classification of such
reserves based on risk of recovery and estimates of future net revenues expected
therefrom, prepared by different engineers or by the same engineers at different
times, may vary substantially. Canadian Natural's actual production, revenues,
taxes and development, abandonment and operating expenditures with respect to
its reserves will likely vary from such estimates, and such variances could be
material.
Estimates with respect to reserves that may be developed and produced in the
future are often based upon volumetric calculations and upon analogy to similar
types of reserves, rather than upon actual production history. Estimates based
on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be material, in the
estimated reserves.
Priority of Subsidiary Indebtedness; Consequences of Holding Corporation
Structure
The Company carries on business through corporate and partnership subsidiaries.
The majority of the Company's assets are held in one or more corporate or
partnership subsidiaries. The results of operations and ability to service
indebtedness, including debt securities, are dependent upon the results of
operations of these subsidiaries and the payment of funds by these subsidiaries
to the Company in the form of loans, dividends or otherwise. In the event of the
liquidation of any corporate or partnership subsidiary, the assets of the
subsidiary would be used first to repay the indebtedness of the subsidiary,
including trade payables or obligations under any guarantees, prior to being
used by the Company to pay its indebtedness.
14
ENVIRONMENTAL MATTERS
The Company carries out its activities in compliance with all relevant regional,
national and international regulations and best industry practice. Environmental
specialists in the UK and Canada review the operations of the Company's
world-wide interests and report on a regular basis to the senior management of
the Company, which in turn reports on environmental matters directly to the
Health, Safety and Environmental Committee of the Board of Directors.
The Company regularly meets with, and submits to inspections by the various
governments in the regions where the Company operates. At present, the Company
believes that it meets all existing environmental standards and regulations and
has included appropriate amounts in its capital expenditure budget to continue
to meet current environmental protection requirements. Since these requirements
apply to all operators in the crude oil and natural gas industry, it is not
anticipated that the Company's competitive position within the industry will be
adversely affected. The Company has internal procedures designed to ensure that
the environmental aspects of new acquisitions and developments are taken into
account prior to proceeding. The Company's environmental management plan and
operating guidelines focus on minimizing the environmental impact of field
operations while meeting regulatory requirements and corporate standards. The
Company's proactive program includes: an environmental compliance audit and
inspection program of our operating facilities; an aggressive suspended well
inspection program to support future development or eventual abandonment;
appropriate reclamation and decommissioning standards for wells and facilities
ready for abandonment; an effective surface reclamation program; progressive due
diligence related to groundwater monitoring; prevention of and reclamation of
spill sites, greenhouse gas reduction, and flaring and venting reduction.
Canadian Natural has participated in Canada's Climate Change Voluntary Challenge
& Registry Inc (VCR) and plans to participate in a new Canadian Standards
Association (CSA) program when the transition from VCR to CSA is complete. The
Company has participated in the Canadian Association of Petroleum Producers
(CAPP) Stewardship Program since 2000 and is currently a Gold Level Reporter.
Canadian Natural continues to invest in proven and new technologies and in
improved operating strategies that will help us achieve our overall goal of a
net reduction of greenhouse gas emissions per unit of production.
The costs incurred by the Company for compliance with environmental matters and
site restoration costs amount to less than 3 per cent of the total exploration
and development expenditures incurred by the Company in each of the years ended
December 31, 2004, 2003, and 2002.
DESCRIPTION OF THE BUSINESS
CNRL is a Canadian based senior independent energy company engaged in the
acquisition, exploration, development, production, marketing and sale of crude
oil, natural gas liquids and natural gas. The Company's principal core regions
of operations are western Canada, the United Kingdom sector of the North Sea and
Offshore West Africa.
The Company focuses on exploiting its core properties and actively maintaining
cost controls. Whenever possible CNRL takes on significant ownership levels,
operates the properties and attempts to dominate the local land position and
operating infrastructure. The Company has grown through a combination of
internal growth and strategic acquisitions. Acquisitions are made with a view to
either entering new core regions or increasing dominance in existing core
regions.
15
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces: namely
natural gas, NGLs, light crude oil, Pelican Lake crude oil, primary heavy crude
oil and thermal heavy crude oil. The Company's operations are centred on
balanced product offerings, which together provide complementary infrastructure
and balance throughout the business cycle. Natural gas is the largest single
commodity sold, accounting for 45 per cent of 2004 production. Virtually all of
the Company's natural gas and natural gas liquids production is located in the
Canadian provinces of Alberta and British Columbia and is marketed in Canada and
the United States. Light oil and NGLs, representing 24 per cent of 2004
production, is located principally in the Company's North Sea and Offshore West
Africa properties, with additional production in the Provinces of Saskatchewan,
British Columbia and Alberta. Primary and thermal heavy oil operations in the
Provinces of Alberta and Saskatchewan account for 27 per cent of 2004
production. Other heavy oil, which accounts for 4 per cent of 2004 production,
is produced from the Pelican Lake area in north Alberta. This production, which
has medium oil netback characteristics, is developed through a staged horizontal
drilling program. Midstream assets, comprised of three crude oil pipelines and
an electricity co-generation facility, provide cost effective infrastructure
supporting the heavy and Pelican Lake crude oil operations. CNRL expects its
ownership of oil sands leases near Ft. McMurray, Alberta to provide a basis for
long-term synthetic oil production growth.
As a result of the Company's core undeveloped land base of 11.5 million net
acres in western Canada, its international concessions and the Alberta oil sands
leases, the Company believes it has sufficient project portfolios in each of the
product offerings to provide growth for the next several years.
16
A. PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES
Set forth below is a summary of the principal crude oil and natural gas
properties as at December 31, 2004. The information is proportionate to the
working interests owned by the Company.
2004 AVERAGE
DAILY YEAR ENDED
PRODUCTION DECEMBER 31, MAJOR INFRASTRUCTURE
RATES 2004 AS AT DECEMBER 31, 2004
--------------- ------------ -----------------------
BATTERIES/
OIL & NATURAL UNDEVELOPED COMPRESSORS & PLANTS/
NGLs GAS ACREAGE PLATFORMS
REGION Mbbls MMcf (thousands) /FPSO
- ------ ----- ------- ----------- ---------------------
North America
Northeast B. C. 6.8 437.3 2,040 1/8/-/-
Northwest Alberta 10.9 303.2 1,660 -/7/-/-
Northern Plains 166.3 429.9 6,922 9/5/-/-
Southern Plains 12.7 155.5 661 -/-/-/-
Southeast Saskatchewan 9.3 3.1 123 -/-/-/-
Non - core regions 0.2 1.1 1,822 -/-/-/-
Horizon Oil Sands -- -- 117 -/-/-/-
International
North Sea 64.7 50.4 565 -/-/5/3
Offshore West Africa
Cote d'Ivoire 11.6 7.5 276 -/-/1/1
Angola -- -- 610 -/-/-/-
South Africa -- 5,550 -/-/-/-
----- ------- ------ ---------
Total 282.5 1,388.0 20,346 10/20/6/4
----- ------- ------ ---------
17
Drilling Activity
Set forth below is a summary of the drilling activity, excluding stratigraphic
test and service wells, of the Company for each of the last three fiscal years
up to December 31, 2004 by geographic region:
2004
---------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
------------------------------ ------------------------------
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
---------- --------- ----- ---------- --------- -----
Canada
Northeast B. C 23.8 6.2 30 146.8 14.4 161.2
Northwest Alberta 42.8 7.6 50.4 100.4 3.9 104.3
Northern Plains 116.6 26.6 143.2 333.8 23.2 357
Southern Plains 18.5 7.0 25.5 209.9 4.0 213.9
Southeast Saskatchewan -- -- -- 12.5 0 12.5
Non - core regions -- -- -- 0.5 0.3 0.8
North Sea -- 2.0 2.0 9.2 0.0 9.2
Offshore West Africa
Cote d'Ivoire -- 0.7 0.7 2.3 0.0 2.3
Angola -- -- -- -- -- --
----- ---- ----- ----- ---- -----
Total 201.7 50.1 251.8 815.4 45.8 861.2
----- ---- ----- ----- ---- -----
2003
-----------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
------------------------------ --------------------------------
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
---------- --------- ----- ---------- --------- -------
Canada
Northeast B. C 15.5 13.3 28.8 67.8 9.1 76.9
Northwest Alberta 31.7 11.8 43.5 69.9 7.9 77.8
Northern Plains 57.5 26.6 84.1 531.6 37.9 569.5
Southern Plains 33.0 4.0 37.0 387.9 5.0 392.9
Southeast Saskatchewan -- -- -- 26.9 -- 26.9
Non - core regions -- -- -- 0.4 -- 0.4
North Sea -- 1.0 1.0 11.1 0.8 11.9
Offshore West Africa
Cote d'Ivoire 0.7 -- 0.7 0.7 -- 0.7
Angola -- 0.6 0.6 -- -- --
----- ---- ----- ------- ---- -------
Total 138.4 57.3 195.7 1,096.3 60.7 1,157.0
----- ---- ----- ------- ---- -------
2002
---------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
------------------------------ ------------------------------
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
---------- --------- ----- ---------- --------- -----
Canada
Northeast B. C 16.8 4.4 21.2 25.4 -- 25.4
Northwest Alberta 3.9 3.0 6.9 6.1 -- 6.1
Northern Plains 31.5 6.0 37.5 278.1 8.6 286.7
Southern Plains 12.0 -- 12.0 40.6 2.5 43.1
Southeast Saskatchewan -- -- -- 4.3 1.0 5.3
North Sea 0.4 -- 0.4 4.5 -- 4.5
Offshore West Africa
Cote D'Ivoire 0.6 0.9 1.5 1.8 0.6 2.4
----- ---- ----- ----- ---- -----
Total 65.2 14.3 79.5 360.8 12.7 373.5
----- ---- ----- ----- ---- -----
18
Producing Oil & Natural Gas Wells
Set forth below is a summary of the number of gross and net wells within the
Company that were producing or capable of producing as of December 31, 2004:
NATURAL GAS WELLS OIL WELLS TOTAL WELLS
----------------- --------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ------- ----- ------- ------ --------
Canada
Northeast B. C. 937 816.0 173 135.6 1,110 951.7
Northwest Alberta 894 745.2 252 149.9 1,146 895.1
Northern Plains 2,619 2,148.4 5,029 4,457.4 7,648 6,605.8
Southern Plains 4,184 3,557.1 1,832 1,705.8 6,016 5,262.9
Southeast Saskatchewan -- -- 991 752.2 991 752.2
Non - core regions 738 107.5 301 160.6 1,039 268.1
United States 4 0.5 2 0.2 6 0.7
North Sea 2 0.1 106 88.5 108 88.6
Offshore West Africa
Cote d'Ivoire -- -- 5 2.9 5 2.9
Angola -- -- -- -- -- --
----- ------- ----- ------- ------ --------
Total 9,378 7,374.8 8,691 7,453.1 18,069 14,827.9
----- ------- ----- ------- ------ --------
All reserves data in the following property report was based on the applicable
independent engineering report. See below "Crude Oil and Natural Gas Reserves".
Northeast British Columbia
[GRAPHIC]
This region comprises lands from Fort St. John, British Columbia to the northern
border as well as the eastern border of British Columbia. Similar geological
attributes extend throughout the region, producing light crude oil, natural gas
liquids and natural gas. The Company holds working interests ranging up to 100
per cent and averaging 74 per cent in 3,799,223 gross (2,812,965 net) acres of
producing and undeveloped land in the region.
19
Crude oil reserves are found primarily in the Halfway or lower Halfway
formation, while natural gas and associated natural gas liquids are found in
numerous zones at depths reaching approximately 2,500 vertical meters. In the
southern portion of the region, the Company owns natural gas producing and
undeveloped lands in which the productive zones are at deeper depths up to 3,500
meters. The exploration strategy focuses on comprehensive evaluation through
two-dimensional seismic, three-dimensional seismic and targeting economic
geological areas close to existing infrastructure. Natural gas production from
the region averaged 437.3 million cubic feet per day for 2004 compared to the
average of 372.3 million cubic feet per day produced for 2003. Crude oil and
natural gas liquids production was steady at to 6.8 thousand barrels per day in
2004 from an average of 6.7 thousand barrels per day in 2003.
This region also contains the Ladyfern Slave Point natural gas pool, which was
placed on production in mid-2001. Prior to the first quarter of 2002, production
from the pool had been restricted due to insufficient processing facilities and
pipelines, with production exiting 2001 at approximately 150 million cubic feet
per day. In the first quarter of 2002, additional facilities were constructed,
which enabled the Company to increase production to approximately 210 million
cubic feet per day in June 2002. In late August 2002, water encroachment
resulted in the commencement of anticipated significant declines from the pool.
At the end of 2002, production was at 100 million cubic feet per day, falling to
approximately 31 million cubic feet per day in December 2003. In May of 2004 the
Company acquired additional lands, facilities and production in the area.
Through the acquisition of Ranger in 2000, the Company acquired an interest and
operatorship in extensive acreage adjacent to the northern border of this
region. A further acquisition in the fourth quarter of 2001 resulted in the
Company obtaining 100 per cent ownership in its producing natural gas assets and
undeveloped land in the Helmet area of the region. Further development of this
acreage will be enhanced through the facilities and infrastructure owned by the
Company in the region. Having identified optimal drilling strategies in the
region, the Company implemented a multi-well annual drilling program, which has
resulted in 30 to 50 wells being drilled in the area each year.
During 2004, the Company developed a new exploration and development program
that targets natural gas found in the shallow Notikewin formation in the Fort
St. John area. Wells drilled into this formation produce at rates of up to 500
to 700 thousand cubic feet per day. In combination with the Company's extensive
land base and the recently reduced royalty rates in British Columbia, this
shallow gas drilling program will add to the Company's opportunities in this
region.
During 2004 the Company drilled 3.6 (2003- 5.1) net oil wells, 167.0 (2003 -
78.2) net natural gas wells, 1.0 (2003 - 0) net stratigraphic/service wells and
20.6 (2003 - 22.4) net dry wells on its lands in this region for a total of
192.2 (2003 - 105.7) net wells. The Company held an average 92.9 per cent
working interest in these wells.
20
Northwest Alberta
[GRAPHIC]
The Company holds working interests ranging up to 100 per cent and averaging 76
per cent in 2,865,122 gross (2,166,652 net) acres of producing and undeveloped
land in the region located along the border of British Columbia and Alberta west
of Edmonton.
The majority of the Company's holdings in the region were obtained through the
Plan of Arrangement in 2002, which facilitated the acquisition of RAX. This
region contains exceptional exploration and exploitation opportunities as well
as substantial available capacity within an extensively owned and operated
infrastructure. In this region, Canadian Natural produces liquids rich natural
gas from multiple, often technically complex horizons, with formation depths
ranging from 700 to 4,500 metres. The northern portion of this core region
provides extensive multi-zone Cretaceous opportunities similar to the geology of
the Company's North Alberta core region. The southern portion provides a
significant opportunity in the regionally extensive Cretaceous Cardium zone. The
Cardium is a complex, tight natural gas reservoir where high productivity may be
achieved due to greater matrix porosity or natural fracturing.
Natural gas production from the region averaged 303.2 million cubic feet per day
for 2004 compared to an average of 261.3 million cubic feet per day for 2003.
Crude oil and natural gas liquids production was steady at 10.9 thousand barrels
per day in 2004 from 11.1 thousand barrels per day in 2003.
During 2004 the Company drilled 5.8 (2003-3.7) net oil wells, 137.5 (2003-97.9)
net natural gas wells, 1.5 (2003 - 0) net stratigraphic/service wells, and 11.5
(2003-19.7) net dry wells on its lands in this region for a total of 156.3
(2003-121.3) net wells. The Company held an average 82.6 per cent working
interest in these wells.
21
Northern Plains
[GRAPHIC]
The Company holds working interests ranging up to 100 per cent and averaging 82
per cent in 11,829,563 gross (9,667,926 net) acres of producing and undeveloped
land in the region located just south of Edmonton north to Fort McMurray and
from the northwest Alberta border east to the border with Saskatchewan and
extending into western Saskatchewan.
Over most of the region both sweet and sour natural gas reserves are produced
from numerous productive horizons at depths up to approximately 1,500 meters. In
the southwest portion of the region, natural gas liquids and light crude oil are
also encountered at slightly deeper depths. The region continues to be one of
the Company's largest natural gas producing regions, with natural gas production
from the region amounting to 429.9 million cubic feet per day in 2004 compared
to 462.4 million cubic feet per day in 2003. Crude oil and natural gas liquids
production from this region increased to 166.3 thousand barrels per day in 2004
from 136.7 thousand barrels per day in 2003. Production of natural gas was
impacted by the shut-in effective July 1, 2004 of approximately 11 million cubic
feet per day in the Athabasca Wabiskaw-McMurray oil sands area pursuant to the
decision of the Alberta Energy and Utilities Board.
In the area near Lloydminster, Alberta, reserves of heavy crude oil (averaging
12 DEG.-14 DEG. API) and natural gas are produced through conventional vertical,
slant and horizontal well bores from a number of productive horizons up to 1,000
meters deep. The energy required to flow the heavy crude oil to the wellbore in
this type of heavy oil reservoir comes from solution gas. The crude oil
viscosity and the reservoir quality will determine the amount of crude oil
produced from the reservoir, which will vary from 3 to 20 per cent of the
original oil in place. A key component to maintaining profitability in the
production of heavy crude oil is to be a low cost producer. The Company
continues to achieve low costs producing heavy oil by holding a dominant
position that includes a significant land base and an extensive infrastructure
of batteries and disposal facilities.
In the area around Elk Point, Ranger owned significant land and production in
this region, with much of its land being contiguous to the Company's holdings.
With the operations combined in 2000, future development of the total lands in
the region became more effective and provided opportunities for cost savings. As
part of the acquisition of Ranger, the Company also acquired a 50 per cent
interest in the ECHO Pipeline system, a crude oil transportation pipeline; and,
in 2001 the Company acquired the remaining 50 per cent. The pipeline was
extended north to the Company
22
operated Beartrap field during 2001, enhancing further development of the
Company's extensive holdings in the area. This pipeline was capable of
transporting 57 thousand barrels per day of hot unblended crude oil to sales
facilities at Hardisty, Alberta and in 2003 its capacity was expanded to handle
up to 72 thousand barrels per day. The ECHO Pipeline system is a high
temperature, insulated pipeline that eliminates the requirement for field
condensate blending. The pipeline enables the Company to transport its own
production volumes at a reduced operating cost as well as earn third party
transportation revenue. The ECHO Pipeline system permits the Company to
transport approximately 80 per cent of its heavy crude oil to the international
mainline liquids pipelines. This transportation control enhances the Company's
ability to control the full spectrum of costs associated with the development
and marketing of its heavy crude oil.
On February 18, 2004 the Company purchased the Petrovera Partnership which added
additional properties in this region. Approximately one third of the total
acquisition was sold to another independent producer. The properties that were
retained further consolidated the Company's position in the area.
Production from the 100% owned Primrose and Wolf Lake fields located near
Bonnyville, Alberta involve processes that utilize steam to increase the
recovery of the oil. The two processes employed by the Company are cyclic steam
stimulation and Steam Assisted Gravity Drainage ("SAGD"). Both recovery
processes inject steam to heat the heavy crude oil deposits, reducing the oil
viscosity and therefore improving its flow characteristics. There is also an
infrastructure of gathering systems, a processing plant with a capacity of 60
thousand barrels per day and a 50 per cent interest in a co-generation facility
capable of producing 84 megawatts of electricity for the Company's use and sale
into the Alberta power grid at pool prices. In 2000, the Company successfully
converted and tested two existing pads of wells from low-pressure steaming to
high-pressure steaming. This conversion increased average production at the 20
existing wells from 100 to 190 barrels of crude oil per day per well. An
additional 24 wells were drilled using the high-pressure steam process with
initial production averaging 600 barrels of crude oil per day per well. These
results have confirmed the benefits of converting the Primrose field to
high-pressure steaming. In 2001, the Company received regulatory approval to
convert an additional six low-pressure cyclic pads to high-pressure cyclic pads,
and in 2002 received approval to take high-pressure steam methodologies
throughout the field. Canadian Natural drilled 58 high-pressure wells in 2004.
Additional development of the leases will be undertaken in phases over the next
several years. The Company in 2004 started to proceed with its Primrose North
expansion project which is expected to be completed by November 2005. The
Primrose North expansion entails a remote steam treating facility and additional
high pressure wells which are expected to be on production in 2006. A successful
SAGD heavy oil project in which the Company holds a 50 per cent interest is also
in operation in the Saskatchewan portion of this region.
Included in the northern part of this region, approximately 200 miles north of
Edmonton, are the Company's approximately 100 per cent owned holdings at Pelican
Lake. These lands contain reserves of 14 DEG.-17 DEG. API heavy oil. Operating
costs are low due to no sand production or disposal requirements and the
gathering and pipeline facilities in place. The Company has the major ownership
position in the necessary infrastructure including roads, drilling pads,
gathering and sales pipelines, batteries, gas plants and compressors to ensure
future economic development of the large crude oil pool located on the lands.
The Company holds and controls approximately 75 percent of the known crude oil
pool in this area.
This field contains approximately three billion barrels of original oil-in-place
but is only expected to achieve a 5 percent recovery factor using existing
primary technologies on the Company's developed leases. Hence, in 2002 the
Company embarked upon an Enhanced Oil Recovery
23
("EOR") scheme using an emulsion flood to increase the ultimate recoveries from
the field. The experimental Pelican Lake emulsion flood showed that the recovery
mechanism was very efficient; however, response time is slow. In view of the
slow response time, the Company has reverted to a waterflood scheme for this
field, which will increase the overall recovery factor but not to the extent
reached under an emulsion scheme. The implementation plan will result in the
conversion of existing producing wells into water injectors and the drilling of
additional producing wells. The Company will also examine opportunities to use
polymer flooding in conjunction with waterflooding to obtain the highest
recovery factor while maximizing value. This pilot is expected to commence in
the second quarter of 2005.
During 2004, the Company drilled 287.0 (2003 - 405.7) net oil wells, 163.4 (2003
- - 183.4) net natural gas wells, 112.0 (2003 - 63.5) net stratigraphic/service
wells, and 49.8 (2003 - 64.5) net wells dry wells for a total of 612.2 (2003 -
717.1) net wells. The Company's average working interest in these wells was 91.4
per cent.
Southern Plains and Southeast Saskatchewan
[GRAPHIC]
In the Southern Plains area, the Company holds interests ranging up to 100 per
cent and averaging 82 per cent in 1,771,346 gross (1,451,816 net) acres of
producing and undeveloped land in the region principally located south of the
Northern Plains area to the United States border and to the east bounded by the
Alberta-Saskatchewan border.
Reserves of natural gas, condensate and light and medium gravity crude oil are
contained in numerous productive horizons at depths up to 2,300 meters. Unlike
the Company's other three natural gas producing regions, which have areas with
limited or winter access only, drilling can take place in this region throughout
the year. With a higher sales price for natural gas, it is economic to drill
shallow wells in closer proximity to each other, which may have smaller overall
reserves and lower productivity per well but will achieve a high return on
capital employed with low drilling costs and longer life reserves.
The Company maintains a large inventory of drillable locations on its land base
in this region. This region is in the most mature portion of the Western
Canadian Sedimentary Basin and requires
24
continual operational cost control through efficient utilization of existing
facilities, flexible infrastructure design and consolidation of interests where
appropriate.
The Company's share of production in the Southern Plains area averaged 12.7
(2003 - 10.9) thousand barrels of crude oil and natural gas liquids per day and
155.5 (2003- 141.9) million cubic feet of natural gas per day in 2004.
During 2004, the Company drilled a total of 7.8 (2003 - 4.4) net oil wells,
220.6 (2003 - 416.5) net natural gas wells, 1.0 (2003 - 0.0) net
stratigraphic/service well and 11.0 (2003 - 9.0) net dry wells in this region
for a total of 240.4 (2003 - 429.9) net wells. The Company's average working
interest in these wells was 86.5 per cent.
The Williston Basin is located in Southeastern Saskatchewan with lands extending
into Manitoba. This region became a core region of the Company in mid 1996 with
the acquisition of Sceptre. The Company holds interests ranging up to 100 per
cent and averaging 80 per cent in 246,304 gross (196,200 net) acres of producing
and undeveloped lands in the region.
The region produces primarily light sour crude oil from as many as seven
productive horizons found at depths up to 2,700 meters. The Company's share of
production in the Southeast Saskatchewan area averaged 9.3 (2003 - 9.2) thousand
barrels of crude oil and natural gas liquids per day and 3.1 (2003- 3.4) million
cubic feet of natural gas per day in 2004.
The Company drilled 12.5 (2003 - 26.9) net oil wells with 0.0 (2003 - 0.0) net
dry wells in this region in 2004, for a total of 12.5 (2003 - 26.9) net wells.
The Company's average working interest in these wells is 65.9 per cent.
United Kingdom North Sea
[GRAPHIC]
The Company's wholly owned subsidiary CNR International (U.K.) Limited, formerly
Ranger Oil (U.K.) Limited, has operated in the North Sea for 30 years and has
developed a significant database, extensive operating experience and an
experienced staff. The Company owns interests ranging from 7 per cent up to 100
per cent in 876,422 gross (657,802 net) acres of producing and non-producing
properties in the UK sector of the North Sea. In 2004, the Company produced from
15 crude oil fields.
25
The northerly fields are centered around the Ninian Field where the Company has
an 87.1 per cent working interest. The central processing facility is connected
to other fields including the Columba Terraces and Lyell Fields where the
Company operates with working interests of 91.6 per cent to 100 per cent. In
2002, the Company completed property acquisitions in the northern North Sea that
increased ownership levels in the Ninian, Murchison, Lyell and Columba Terraces
Fields. As part of the transaction the Company also acquired an interest in the
Strathspey Field and 12 licenses covering 20 exploration blocks and part blocks
surrounding the Ninian and Murchison platforms. Increased ownership in the Brent
and Ninian pipelines and the Sullom voe Terminal was also acquired. In 2003 the
Company further consolidated its ownership with the acquisition of additional
working interests in the Ninian and Columba Fields, associated facilities and
adjacent exploration acreage.
In the central portion of the North Sea, in 2003 the Company increased its
equity in the Banff Field to 87.6 per cent and took over as operator. In 2004
the Company acquired 100 per cent working interest in T-block (comprising the
Tiffany, Toni and Thelma Fields) and 68.7 per cent to 75.3 per cent interests in
the Fields known as B-block (comprising Balmoral, Stirling and Glamis). The
Company took over as operator of these fields. The Company also owns a 45.7 per
cent operated working interest in the Kyle Field.
Ownership and operatorship levels in the North Sea are now similar to those
levels found throughout the Company's other worldwide operations. The Company
also receives tariff revenue from other field owners for the processing of crude
oil and natural gas through some of the processing facilities. Opportunities for
further long-reach well development on adjacent fields are provided from the
existing processing facilities.
During 2004, production to the Company from this region averaged 64.7 (2003 -
56.9) thousand barrels of crude oil per day and 50.4 (2003 - 45.6) million cubic
feet of natural gas per day. The Company drilled 9.2 (2003 - 11.1) net oil
wells, 2.7 (2003 - 4.8) net service wells and 2.0 (2003 - 1.8) net dry wells in
2004 in this region for a total of 13.9 (2003 - 17.7) net wells. The Company's
average working interest in these wells is 92.3 per cent.
Offshore West Africa
[GRAPHIC]
With the purchase of Ranger in 2000, the Company acquired interests in areas of
crude oil and natural gas exploration and development offshore Cote d'Ivoire and
Angola, West Africa. The Company owns working interests ranging from 50 per cent
to 100 per cent in 1,589,213 gross
26
(885,541 net) acres in those countries. The Company also has a 100 per cent
interest in 5,550,428 acres offshore South Africa where it is shooting and
evaluating seismic.
Cote d'Ivoire
The Company owns interests in three exploration licences offshore Cote d'Ivoire
comprising 275,625 net acres. During 2001, the Company increased its interest in
Block CI-26, which contains the Espoir Field, to a 59 per cent operating
interest. The Espoir Field is located in water depths ranging from 100 to 700
meters. During the 1980s, the Espoir Field produced approximately 31 million
barrels of crude oil by natural depletion prior to relinquishment by the
previous licencees in 1988. The government of Cote d'Ivoire approved a
development plan to recover the remaining reserves and the Company will continue
its exploitation and development of the field. The first phase of development of
East Espoir, which includes the drilling of both producing and water injection
wells from a single wellhead tower, was completed in 2003. Finalization of an
infill drilling program in East Espoir and development plans for the West Espoir
part of the Field were completed in 2004. Oil from the East Espoir is produced
into an FPSO with associated natural gas delivered onshore through a subsea
pipeline for local power generation. In 2003 the Company drilled a satellite
pool, Acajou, which encountered a reservoir with good quality and hydrocarbons.
The extent of this accumulation was further appraised by a well drilled in 2004
which did not encounter commercial hydrocarbons.
In the first quarter of 2001, the Company drilled and tested the Baobab
exploration prospect, identified on Block CI-40, in which the Company has a 58
per cent interest, eight kilometres south of the Espoir facilities. The well
encountered hydrocarbons at a rate of 6.7 thousand barrels of crude oil per day.
A second test well in 2002 also produced hydrocarbons at a rate in excess of 10
thousand barrels of crude oil per day. The Company established a field
development plan, which was approved by the Government of Cote d'Ivoire in
December 2002. In 2003 the Company awarded four major contracts for the
development of the Baobab Field. These contracts included the deep water
drilling rig to drill 8 producing and 3 water injection wells, the FPSO,
supplies for the subsea equipment and the supply of pipeline and risers, and
installation of the subsea infrastructure. Development commenced in late 2003
and is progressing according to plan towards first oil in 2005.
To date political unrest in Cote d'Ivoire has had no impact on the Company's
operations. The Company has developed contingency plans to continue Cote
d'Ivoire operations from another nearby country if the situation warrants such a
move.
During 2004, net daily production to the Company averaged 11.6 (2003 - 10.6)
thousand barrels of crude oil and 7.5 (2003 - 8.4) million cubic feet of natural
gas. In 2004, the Company drilled 2.3 (2003 - 1.3) net oil wells, 0.0 (2003 -
2.0) net service wells and 0.7 (2003 - 0.0) net dry wells for a total of 3.0
(2003 - 3.3) net wells. The Company's average working interest in these wells is
59.3 per cent.
Angola
During 2002, the Company was awarded operatorship and a 50 per cent working
interest in exploration Block 16 situated offshore The People's Republic of
Angola. 3-D seismic was obtained over the entire Block 16 before obtaining title
and identified two targets, Omba in the north and Zenza in the west central
portion of the Block. The Company has a two well commitment over a four year
time frame expiring August 31, 2006. The first well, Zenza-1, was drilled during
the fourth quarter of 2003 and was not considered commercial. Following further
evaluation of seismic and the well results during 2004, the Company is
considering various options, including divestment.
27
The Company also owned 100 per cent of and operated the offshore Kiame Field.
The field produced from June 1998 to April 2002 through a leased FPSO. The field
reached its economic limit of production and production ceased in April 2002.
The wells were abandoned and the associated seabed equipment safely recovered
during 2003. The Company also had a 25 per cent non-operating interest in Block
19, on which a 3-D seismic survey was completed in 1999. After interpretation of
the seismic and drilling of a 25 per cent interest well in 2002 on Block 19, the
Company determined the block was not economic to develop and relinquished its
license on the block.
Horizon Oil Sands Project
Canadian Natural owns a 100 percent working interest in 116,596 gross acres in
the Athabasca Oil Sands area of Northern Alberta. The Horizon Oil Sands Project
("the Horizon Project") is located on these leases, about 80-km north of Fort
McMurray. The project includes surface oil sands mining, bitumen extraction,
bitumen upgrading to produce a 34-36o API synthetic light crude oil ("SCO"), and
associated infrastructure.
The project, which has two aspects; namely, bitumen production and bitumen
upgrading to SCO, is designed as a phased development. Site clearing and
pre-construction preparation activities commenced in 2004 and construction will
continue through 2012. Phase 1 production is planned to begin in the fourth
quarter of 2008 at 110 thousand barrels per day of SCO. Phase 2 would increase
production to 155 thousand barrels per day of SCO in 2010. Phase 3 would further
increase production to 232 thousand barrels per day of SCO in 2012. These
projected rates of production represent nominal design capacity. Canadian
Natural will seek to maximize resource recovery and overall production through
ongoing optimization of operations. The phased approach provides the Company
with improved cost and project controls in terms of labour and materials
management and directionally mitigates the effects of growth on local
infrastructure.
Total estimated capital costs of the phased development are $10.8 billion, of
which approximately $6.8 billion including contingency funding of $700 million
would be required for Phase 1. When the Horizon Project is fully commissioned,
operating costs - including sustaining capital - are expected to be in the range
of $14 per barrel.
Canadian Natural filed an application for regulatory approval of the Horizon
Project in June 2002. The application included a comprehensive environmental
impact assessment, a social and economic assessment and was accompanied by
public consultation. A federal-provincial regulatory Joint Review Panel (the
"Panel") examined the project in a public hearing in September 2003. The Panel
issued its decision report in January 2004, finding that the Horizon Project is
in the public interest. An Alberta Order-in-Council approval was received in
February 2004. Subsequently, key approvals were received from Alberta
Environment under the Environmental Protection Act and Water Act, and from
Fisheries and Oceans Canada under the Fisheries Act.
Throughout the first half of 2003, Canadian Natural, along with other major
energy project proponents and the Canadian Association of Petroleum Producers
actively sought greater clarity from the federal government about the long-term
climate change policy framework. Of particular concern was the period beyond
2012 when policies will be derived from Canada's negotiations for a second Kyoto
implementation phase. In mid 2003 the Government of Canada acknowledged the need
for greater clarity and established eight principles that will guide the
Government of Canada's longer-term climate change policies. These eight guiding
principles addressed the key concerns of Canadian Natural with regard to
equability, efficiency, flexibility and competitiveness issues for the post-2012
period.
28
Canadian Natural used a structured system called Front End Loading to ensure
that project definition is adequate and complete before proceeding with
implementation. This system is used successfully worldwide to mitigate risk on
large capital projects in a variety of industries. The process is well
documented at every step and is audited by an independent organization. In June
2002, the Company commenced the Design Basis Memorandum (DBM), which is the
second of three front-end engineering phases. The DBM was completed for all
project components in February 2004. In August 2003, the Company commenced work
on the third and final front-end engineering phase, completing the work in
December 2004. The products of this phase include a detailed project execution
plan, Engineering Design Specifications ("EDS") and a detailed cost estimate
(plus or minus 10%). The EDS provided sufficient definition for a lump sum
inquiry for the Detailed Engineering, Procurement and Construction of the
various project components. With this information a "cost certainty" estimate
was developed as a basis for project sanction by the Board of Directors which
was given in February 2005 authorizing management to proceed with Phase 1 of the
Horizon Oil Sands Project.
Horizon is designed to use proven technology and will seek to take advantage of
technology improvements that advance environmental performance, enhance the work
environment for workers, increase reliability and production and reduce capital
and operating costs. By the end of 2004 the Company had acquired all key
technologies for the project. At year end, Horizon Project staff, including
direct hire and contract, representing the many skill disciplines required to
define and implement the project numbered 800, about 75% of the required staff
compliment to implement Phase 1.
Canadian Natural expended $291 million on the Horizon Project in 2004.
Cumulative expenditures on the project are $672 million to the end of 2004.
These expenditures include lease evaluation, engineering definition, technology
acquisition, environmental and socio-economic assessment, public consultation,
regulatory application, completion of road infrastructure to the site and
preliminary site development. Capital expenditures for 2005 are budgeted to be
$1.4 billion reflecting the beginning of major expenditures for detailed
engineering, procurement and construction of Phase 1 of the Project.
During 2004, the Company drilled 218 (2003 - 370) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.
B. CRUDE OIL AND NATURAL GAS RESERVES
The Company retains independent qualified petroleum engineering consultants
Sproule Associates Limited ("Sproule") and Ryder Scott Company ("Ryder Scott")
to evaluate 100% of the Company's proved and proved and probable crude oil and
natural gas reserves and prepare evaluation reports on the Company's total
reserves ("Evaluation Reports"). The Evaluation Reports are effective December
31, 2004 as prepared February 18, 2005. The Company has been granted an
exemption from the recently adopted National Instrument 51-101 - Standards of
Disclosure for Oil and Gas Activities ("NI 51-101") which prescribes the
standards for the preparation and disclosure of reserves and reserves related
information for companies listed on stock exchanges in Canada. This exemption
allows the Company to substitute United States Securities and Exchange
Commission ("SEC") requirements for certain disclosures required under NI
51-101. The primary difference between the two standards is the additional
requirement under NI 51-101 to disclose both proved and proved plus probable
reserves as well as related future net revenues using forecast prices and costs.
The Company has disclosed proved reserves using constant prices and costs as
mandated by the SEC and has elected
29
to provide proved plus probable reserves and values under the same parameters as
well as proved and proved plus probable reserves using forecast prices and costs
as additional voluntary information. Another difference between the two
standards lies in the definition of proved reserves. As discussed in the
Canadian Oil and Gas Evaluation handbook ("COGEH"), the standards which NI
51-101 employs, the difference in estimated proved reserves based on constant
pricing and costs between the two standards is not material.
The Reserves Committee of the Board of Directors of the Company has met with
each of Sproule and Ryder Scott and carried out the appropriate independent due
diligence procedures with Sproule and Ryder Scott to review the qualifications
of and procedures used by Sproule and Ryder Scott in determining the estimate of
the Company's quantities and value of remaining petroleum and natural gas
reserves.
The following tables summarize the evaluations of reserves and estimated future
net revenues at December 31, 2004.
The estimated future net revenues contained in the following tables are not to
be construed as a representation of the fair market value of the properties to
which they relate. The estimated future net revenues derived from the assets are
prepared prior to consideration of income taxes and existing asset abandonment
liabilities. No indirect costs such as overhead, interest and administrative
expenses have been deducted from the estimated future net revenues. Other
assumptions and qualifications relating to costs, prices for future production
and other matters are summarized in the notes to the following tables. There is
no assurance that the price and cost assumptions contained in either the
constant or forecast cases will be attained and variances could be substantial.
Crude Oil, NGL and Natural Gas Reserves (Net of Royalties)
Constant Prices and Costs
-----------------------------------------------
Net Net
Crude Oil & NGL Reserve Natural Gas Reserve
Volumes (MMbbls) Volumes (Bcf)
----------------------- ---------------------
Total Total
Proved and Proved and
Proved Probable Proved Probable
Reserves Reserves Reserves Reserves
-------- ---------- -------- ----------
North America
Canada 648 926 2,590 3,317
United States 0 0 1 2
International
United Kingdom 303 415 27 57
Cote d'Ivoire 115 196 72 90
----- ----- ----- -----
Total 1,066 1,537 2,690 3,466
===== ===== ===== =====
30
Crude Oil, NGL and Natural Gas Reserves
Constant Prices and Costs
-----------------------------------------
Crude Oil and Natural
Gas Liquids (MMbbls) Natural Gas (Bcf)
--------------------- -----------------
Gross Net Gross Net
--------- --------- ------- -------
Proved developed 638 605 2,761 2,230
Proved undeveloped 485 461 549 460
----- ----- ----- -----
Total proved reserves 1,123 1,066 3,310 2,690
Total proved and probable reserves 1,621 1,537 4,259 3,466
===== ===== ===== =====
Estimated Future Net Revenues
Constant Prices and Costs
---------------------------------------
($ Millions) Undiscounted Discounted at
------------ ------------------------
10% 15% 20%
------ ------ ------
Proved developed 21,092 13,739 11,838 10,453
Proved undeveloped 8,059 4,399 3,440 2,748
------ ------ ------ ------
Total proved reserves 29,151 18,138 15,279 13,201
Total proved and probable reserves 40,088 22,937 18,802 15,899
====== ====== ====== ======
Crude Oil, NGL and Natural Gas Reserves
Forecast Prices and Costs
-----------------------------------------
Crude Oil and Natural
Gas Liquids (MMbbls) Natural Gas (Bcf)
--------------------- -----------------
Gross Net Gross Net
--------- --------- ------- -------
Proved developed 627 582 2,702 2,179
Proved undeveloped 487 451 545 456
----- ----- ----- -----
Total proved reserves 1,114 1,033 3,247 2,635
Total proved and probable reserves 1,617 1,501 4,178 3,394
===== ===== ===== =====
Estimated Future Net Revenues
Forecast Prices and Costs
---------------------------------------
($ Millions) Undiscounted Discounted at
------------ ------------------------
10% 15% 20%
------ ------ ------
Proved developed 17,838 12,708 11,267 10,181
Proved undeveloped 7,856 4,071 3,164 2,528
------ ------ ------ ------
Total proved reserves 25,694 16,779 14,431 12,709
Total proved and probable reserves 35,579 20,985 17,515 15,080
====== ====== ====== ======
NOTES
1. "Gross" reserves means the total working interest share of remaining
recoverable reserves owned by the Company before deduction of royalties
payable to others.
2. "Net" reserves mean the Company's gross reserves less all royalties payable
to others plus royalties receivable from others.
3. "Proved developed" reserves were evaluated using SEC standards and can be
expected to be recovered through existing wells with existing equipment and
operating methods. SEC standards require that these be evaluated using
year-end constant prices and costs and be disclosed net of royalties. The
Company has also provided these reserves and their associated values using
forecast prices and costs as well as before royalties as additional
voluntary information.
31
4. "Proved undeveloped" reserves were evaluated using SEC standards and are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where relatively major expenditures are required for the
completion of these wells or for the installation of processing and
gathering facilities prior to the production of these reserves. Reserves on
undrilled acreage are limited to those drilling units offsetting productive
wells that are reasonably certain of production when drilled. SEC standards
require that these be evaluated using year-end constant prices and costs
and be disclosed net of royalties. The Company has also provided these
reserves and their associated values using forecast prices and costs as
well as before royalties as additional voluntary information.
5. "Proved" reserves were evaluated using SEC standards and are those
quantities of crude oil, natural gas and natural gas liquids, which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic
and operating conditions. SEC standards require that these be evaluated
using year-end constant prices and costs and be disclosed net of royalties.
The Company has also provided these reserves and their associated values
using forecast prices and costs as well as before royalties as additional
voluntary information.
6. "Total Proved and Probable" reserves were evaluated using the COGEH
standards of NI 51-101 and are those reserves where there is at least a 50
per cent probability that the quantities actually recovered will equal or
exceed the stated values. The Company has elected to disclose proved plus
probable reserves and their associated values using both constant prices
and costs as well as forecast prices and costs and has disclosed these
before and net of royalties. The calculation of a probable reserves and
value component by subtracting the proved reserves from the proved plus
probable reserves may be subject to error due to the different standards
applied in the determination of each value. The impact, however, is not
material.
7. Canadian securities legislation and policies permit the disclosure, which
is included or incorporated by reference herein under a
multi-jurisdictional disclosure system adopted by the SEC, of probable
reserves which may not be disclosed in registration statements otherwise
filed with the SEC. Probable reserves are generally believed to be less
likely to be recovered than proved reserves. The reserve estimates,
included or incorporated by reference in this Annual Information Form could
be materially different from the quantities and values ultimately realized.
8. All values are shown in Canadian dollars.
9. The constant price and cost case assumes that prices in effect at the end
of the year adjusted for quality and transportation as well as the 2004
costs are held constant over life. The constant price assumptions assume
the continuance of current laws, regulations and operating costs in effect
on the date of the Evaluation Report. Product prices have not been
escalated beyond 2004. In addition, operating and capital costs have not
been increased on an inflationary basis.
The crude oil and natural gas constant prices used in the Evaluation
Reports are as follows:
NATURAL GAS CRUDE OIL & NGLs
----------------------------------------------- -----------------------------------------------------------
Company Company Hardisty
Average Henry Hub Huntingdon/ Average WTI @ Heavy Edmonton North Sea
Price Louisiana AECO Sumas Price Cushing (i) 12 DEG. API Par (ii) Brent
YEAR $CDN/Mcf $US/MMBtu $CDN/MMBtu $CDN/MMBtu $CDN/bbl $US/bbl $CDN/bbl $CDN/bbl $US/bbl
- ---- -------- --------- ---------- ----------- -------- ----------- ----------- -------- ---------
2004 6.44 6.62(iii) 6.78 6.94 32.14 44.04(iv) 17.45 51.62 40.47
(i) "WTI @ Cushing" refers to the price of West Texas Intermediate crude
oil at Cushing, Oklahoma.
(ii) "Edmonton Par Price" refers to the price of light gravity (40 DEG.
API), low sulphur content crude oil at Edmonton, Alberta.
(iii)There was no trading of Henry Hub on December 31, 2004. This posted
value was determined on the basis of December 30, 2004 posted price
for Henry Hub adjusted for the change in the AECO price as posted by
the Canadian Gas Price Reporter.
(iv) There was no trading on WTI on December 31, 2004. This posted value
was determined on the basis of December 30, 2004 posted price for WTI
adjusted for the change in the Brent price as posted by the Platts
Oilgram Price Report.
(v) Foreign exchange rate used was $0.832 US / $1.00 Cdn.
10. The forecast price and cost cases assume the continuance of current laws
and regulations, and any increases in wellhead selling prices also take
inflation into account. Sales prices are based on reference prices as
detailed below and adjusted for quality and transportation. Reference
prices and costs are escalated at 1.5 per cent per year. Future crude oil,
natural gas liquids and natural gas price forecasts were based on Sproule's
January 1, 2005 crude oil, natural gas liquids and natural gas pricing
model.
32
The Company's weighted average crude oil and NGLs price and the weighted average
natural gas price in 2004 were $37.99 per barrel and $6.50 per mcf respectively,
before adjustments due to hedging. The crude oil and natural gas forecast prices
used in the Evaluation Reports are as follows:
- --------------------------------------------------------------------------------
NATURAL GAS CRUDE OIL & NGLs
----------------------------------------------- -------------------------------------------------------
Company Company Hardisty
Average Henry Hub Huntingdon/ Average WTI @ Heavy Edmonton North Sea
Price Louisiana AECO Sumas Price Cushing 12 DEG. API Par Brent
YEAR $CDN/Mcf $US/MMBtu $CDN/MMBtu $CDN/MMBtu $CDN/bbl $US/bbl $CDN/bbl $CDN/bbl $US/bbl
- ---- -------- --------- ---------- ----------- -------- ------- ----------- -------- ---------
2005 6.63 6.74 6.97 7.13 38.50 44.29 28.91 51.25 42.79
2006 6.31 6.48 6.66 6.92 36.80 41.60 28.12 48.03 40.08
2007 5.84 6.08 6.21 6.47 33.66 37.09 26.19 42.64 34.54
2008 5.36 5.70 5.73 5.99 31.04 33.46 25.06 38.31 31.89
2009 5.01 5.41 5.37 5.63 29.04 31.84 23.60 36.36 30.25
2010 5.10 5.49 5.47 5.73 29.53 32.32 24.12 36.91 30.70
2011 5.24 5.58 5.57 5.83 30.33 32.80 24.64 37.47 31.16
2012 5.32 5.66 5.67 5.93 29.74 33.30 25.17 38.03 31.63
2013 5.40 5.75 5.77 6.03 29.76 33.79 25.71 38.61 32.11
2014 5.49 5.83 5.87 6.13 30.29 34.30 26.26 39.19 32.59
2015 5.59 5.92 5.98 6.24 30.21 34.82 26.82 39.78 33.08
(i) Foreign exchange rate used was $0.84 US / $1.00 Cdn throughout the
forecast
11. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and natural gas liquids,
less all capital costs, production taxes, and operating costs and before
provision for income taxes, administrative overhead costs and existing
asset abandonment liabilities.
12. The estimated total development capital costs net to the Company necessary
to achieve the estimated future net "proved" and "proved and probable"
production revenues are:
PROVED PROVED AND PROBABLE
------------------------------------------------------------------
FORECAST PRICE CONSTANT PRICE FORECAST PRICE CONSTANT PRICE
CASE CASE CASE CASE
($Millions) ($Millions) ($Millions) ($Millions)
-------------- -------------- -------------- ---------------
2005 1,331 1,325 1,465 1,458
2006 541 534 633 621
2007 302 292 472 438
2008 212 199 535 497
2009 133 123 486 452
2010 129 117 402 367
2011 164 305 415 438
2012 81 97 229 151
2013 37 81 171 175
2014 213 62 49 79
2015 120 36 160 46
2016 90 80 54 83
Thereafter 561 460 825 634
13. The Evaluation Reports involved data supplied by the Company with respect
to quality, heating value and transportation adjustments, interests owned,
royalties payable, operating costs and contractual commitments. This data
was audited by Sproule against corporate financial statements and was found
to have no material differences. No field inspection was conducted.
A report on conventional reserves data by Sproule and Ryder Scott and a report
of the Company's management and directors on oil and natural gas disclosure are
provided in Schedules A and B, respectively, to this Annual Information Form.
The Company does not file estimates of its total oil and natural gas reserves
with any U. S. agency or federal authority other than the SEC.
33
C. RECONCILIATION OF CHANGES IN NET RESERVES
The following table summarizes the changes during the past year in reserves
after deduction of royalties payable to others and using constant prices and
costs:
-----------------------------------------------------------------------
CRUDE OIL AND NATURAL GAS
LIQUIDS (MMbbls) NATURAL GAS (Bcf)
---------------------------------- ----------------------------------
Offshore Offshore
North North West North North West
America Sea Africa Total America Sea Africa Total
------- ----- -------- ----- ------- ----- -------- -----
Proved reserves
Reserves, December 31, 2003 588 222 85 895 2,426 62 64 2552
Extensions & Discoveries 17 0 0 17 334 0 0 334
Infill Drilling 24 35 0 59 74 0 0 74
Improved Recovery 1 10 0 11 6 0 0 6
Property purchases 36 38 0 74 182 10 0 192
Property disposals 0 0 0 0 (8) 0 0 (8)
Production (66) (24) (4) (94) (383) (18) (3) (404)
Revisions of prior estimates 48 22 34 104 (40) (27) 11 (56)
--- --- --- ----- ----- --- --- ----
Reserves, December 31, 2004 648 303 115 1,066 2591 27 72 2690
--- --- --- ----- ----- --- --- ----
Proved + Probable reserves
Reserves, December 31, 2003 857 317 133 1,307 2919 102 72 3093
Extensions & Discoveries 20 0 0 20 418 0 0 418
Infill Drilling 29 49 0 78 106 0 0 106
Improved Recovery 2 10 0 12 6 0 0 6
Property purchases 49 49 0 98 236 18 0 254
Property disposals 0 0 0 0 (10) 0 0 (10)
Production (66) (24) (4) (94) (383) (18) (3) (404)
Revisions of prior estimates 35 14 67 116 27 (45) 21 3
--- --- --- ----- ----- --- --- ----
Reserves, December 31, 2004 926 415 196 1,537 3319 57 90 3466
Information on the Company's oil and natural gas reserves is provided in
accordance with United States FAS 69, "Disclosures About Oil and Gas Producing
Activities" in the Company's 2004 Annual Report under "Supplementary Oil and Gas
Information" on pages 91 to 95 and is incorporated herein by reference.
34
D. OIL SANDS MINING RESERVES
Horizon oil sands mining reserves are not part of Canadian Natural's year-end
reserves disclosure. Horizon reserves were evaluated as of February 9, 2005, as
reported in their report dated February 18, 2004, with the authorization by the
Board of Directors to proceed with Phase 1 of the Horizon Oil Sands Project (the
"Horizon Project"). Gilbert Laustsen Jung Associates Ltd. ("GLJ"), a qualified
independent reserves evaluator, was retained by the Reserves Committee of
Canadian Natural's Board of Directors to evaluate reserves associated with the
Horizon Project incorporating both the mining and upgrading projects. These
reserves were evaluated under SEC Industry Guide 7. The Reserves Committee has
met with GLJ and carried out independent due diligence procedures with GLJ as to
the Company's Horizon Project reserves.
The following table sets out, on a gross basis, Canadian Natural's proved and
probable reserves of bitumen and synthetic crude oil from its Oil Sands mining
leases as of February 9, 2005.
Gross Oil Sands Mining Reserves (MMbbls)
----------------------------------------
Proved Probable Proved and Probable
------ -------- -------------------
Bitumen 1,900 1,420 3,320
Synthetic crude oil (1) 1,560 1,230 2,790
(1) Synthetic crude oil reserves are based on upgrading of the bitumen
reserves. The reserves shown for bitumen and synthetic crude oil are not
additive.
A report on Horizon oil sands mining reserves data by GLJ and a report of the
Company's management and directors on mining reserves disclosure are provided in
Schedules "A" and "B", respectively, to this Annual Information Form. The
Company does not file estimates of its total oil and natural gas reserves and
mining reserves with any U. S. agency or federal authority other than the SEC.
E. CRUDE OIL AND NATURAL GAS PRODUCTION
The Company's working interest share of oil, NGLs and natural gas production and
revenues received for the last three financial years is summarized in the
following tables:
YEAR ENDED DECEMBER 31
---------------------------
2004 2003 2002
------- ------- -------
Daily Production
Crude Oil and NGLs (bbls/d) 282,489 242,392 215,335
Natural Gas (MMcf/d) 1,388 1,299 1,232
Annual Production
Crude Oil and NGLs (Mbbls) 103,391 88,473 78,597
Natural Gas (Bcf) 508 474 450
35
NETBACKS
INFORMATION BY QUARTER
YEAR 2004
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
Average Daily Production Volumes
Crude oil and NGL's (bbl) 261,286 275,398 297,262 295,704 282,489
Natural Gas (mcf) 1,294 1,452 1,396 1,410 1,388
Product Netbacks
Crude oil and NGLs ($/bbl)
Sales Price (1) $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99
Royalties $ 2.91 $ 3.15 $ 3.59 $ 2.95 $ 3.16
Production Expenses $ 9.58 $ 9.92 $ 10.21 $ 10.41 $ 10.05
Netback $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78
Natural Gas ($/Mcf)
Sales Price (1) $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50
Royalties $ 1.27 $ 1.38 $ 1.39 $ 1.34 $ 1.35
Production Expenses $ 0.65 $ 0.66 $ 0.71 $ 0.68 $ 0.67
Netback $ 4.39 $ 4.60 $ 4.14 $ 4.75 $ 4.48
Crude Oil and NGL Netbacks by Type
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $ 40.75 $ 45.28 $ 51.54 $ 48.60 $ 46.71
Royalties $ 3.71 $ 3.98 $ 3.99 $ 4.12 $ 3.95
Production Expenses $ 9.77 $ 10.36 $ 10.70 $ 11.20 $ 10.53
Netback $ 27.27 $ 30.94 $ 36.85 $ 33.28 $ 32.23
Heavy ($/bbl)
Sales Price (1) $ 27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99
Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
Netback $ 15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09
YEAR 2003
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
Average Daily Production Volumes
Crude oil and NGL's (bbl) 237,560 240,607 247,016 244,262 242,392
Natural Gas (mcf) 1,310 1,325 1,289 1,270 1,299
Product Netbacks
Crude oil and NGLs ($/bbl)
Sales Price (1) $ 39.37 $ 30.66 $ 31.45 $ 29.47 $ 32.66
Royalties $ 3.56 $ 2.78 $ 2.56 $ 2.22 $ 2.77
Production Expenses $ 10.79 $ 10.80 $ 10.14 $ 9.45 $ 10.28
Netback $ 25.02 $ 17.08 $ 18.75 $ 17.80 $ 19.61
Natural Gas ($/Mcf)
Sales Price (1) $ 7.75 $ 6.25 $ 5.57 $ 5.26 $ 6.21
Royalties $ 1.78 $ 1.35 $ 1.11 $ 1.05 $ 1.32
Production Expenses $ 0.57 $ 0.59 $ 0.63 $ 0.63 $ 0.60
Netback $ 5.40 $ 4.31 $ 3.83 $ 3.58 $ 4.29
Crude Oil and NGL Netbacks by Type
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $ 44.38 $ 34.60 $ 36.06 $ 35.76 $ 37.66
Royalties $ 4.18 $ 3.32 $ 3.11 $ 2.82 $ 3.35
Production Expenses $ 10.42 $ 9.76 $ 9.53 $ 9.65 $ 9.83
Netback $ 29.78 $ 21.52 $ 23.42 $ 23.29 $ 24.48
Heavy ($/bbl)
Sales Price (1) $ 32.44 $ 25.37 $ 25.17 $ 21.45 $ 25.98
Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00
Production Expenses $ 11.30 $ 12.19 $ 10.96 $ 9.19 $ 10.88
Netback $ 18.43 $ 11.12 $ 12.38 $ 10.79 $ 13.10
NOTE: Pelican Lake oil has an API of 14 DEG. to 17 DEG., but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rates.
(1) Including transportation and excluding risk management activities
36
NETBACKS
INFORMATION BY QUARTER
YEAR 2004
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
SEGMENTED
North America Product Netbacks
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $37.54 $41.03 $44.89 $43.80 $41.81
Royalties $ 7.20 $ 7.91 $ 8.59 $ 8.76 $ 8.12
Production Expenses $ 7.30 $ 7.74 $ 7.75 $ 7.85 $ 7.66
Netback $23.04 $25.38 $28.55 $27.19 $26.03
Heavy ($/bbl)
Sales Price (1) $27.00 $28.08 $35.33 $25.16 $28.99
Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
Netback $15.60 $16.30 $22.43 $13.77 $17.09
Natural Gas ($/Mcf)
Sales Price (1) $ 6.37 $ 6.78 $ 6.36 $ 6.88 $ 6.61
Royalties $ 1.33 $ 1.44 $ 1.45 $ 1.39 $ 1.40
Production Expenses $ 0.60 $ 0.60 $ 0.63 $ 0.63 $ 0.62
Netback $ 4.44 $ 4.74 $ 4.28 $ 4.86 $ 4.59
North Sea Product Netbacks
Light Oil ($/bbl)
Sales Price (1) $44.27 $49.22 $57.39 $52.77 $51.37
Royalties $ 0.06 $ 0.10 $ 0.09 $ 0.08 $ 0.08
Production Expenses $13.26 $13.84 $13.88 $14.96 $14.03
Netback $30.95 $35.28 $43.42 $37.73 $37.26
Natural Gas ($/Mcf)
Sales Price (1) $ 5.08 $ 3.28 $ 3.17 $ 3.26 $ 3.73
Royalties $ -- $ -- $ -- $ -- $ --
Production Expenses $ 1.65 $ 1.92 $ 2.48 $ 2.29 $ 2.07
Netback $ 3.43 $ 1.36 $ 0.69 $ 0.97 $ 1.66
Offshore West Africa Product Netbacks
Light Oil ($/bbl)
Sales Price (1) $42.08 $49.34 $53.86 $51.28 $49.05
Royalties $ 1.28 $ 1.52 $ 1.42 $ 1.52 $ 1.43
Production Expenses $ 7.09 $ 7.43 $ 8.05 $ 7.82 $ 7.59
Netback $33.71 $40.39 $44.39 $41.94 $40.03
Natural Gas ($/Mcf)
Sales Price (1) $ 4.80 $ 5.18 $ 6.31 $ 4.73 $ 5.25
Royalties $ 0.15 $ 0.16 $ 0.17 $ 0.14 $ 0.15
Production Expenses $ 1.23 $ 1.38 $ 1.39 $ 1.31 $ 1.33
Netback $ 3.42 $ 3.64 $ 4.75 $ 3.28 $ 3.77
YEAR 2003
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
SEGMENTED
North America Product Netbacks
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $40.89 $32.73 $32.78 $30.95 $34.37
Royalties $ 7.65 $ 6.33 $ 6.04 $ 5.51 $ 6.39
Production Expenses $ 6.09 $ 6.42 $ 6.76 $ 7.24 $ 6.62
Netback $27.15 $19.98 $19.98 $18.20 $21.36
Heavy ($/bbl)
Sales Price (1) $32.44 $25.37 $25.17 $21.45 $25.98
Royalties $ 2.71 $ 2.06 $ 1.83 $ 1.47 $ 2.00
Production Expenses $11.30 $12.19 $10.96 $ 9.19 $10.88
Netback $18.43 $11.12 $12.38 $10.79 $13.10
Natural Gas ($/Mcf)
Sales Price (1) $ 7.88 $ 6.39 $ 5.70 $ 5.35 $ 6.34
Royalties $ 1.84 $ 1.40 $ 1.16 $ 1.10 $ 1.38
Production Expenses $ 0.55 $ 0.56 $ 0.58 $ 0.60 $ 0.57
Netback $ 5.49 $ 4.43 $ 3.96 $ 3.65 $ 4.39
North Sea Product Netbacks
Light Oil ($/bbl)
Sales Price (1) $49.74 $37.08 $39.63 $41.70 $42.00
Royalties $ 0.11 $(0.19) $ 0.09 $(0.15) $(0.03)
Production Expenses $15.50 $14.17 $13.25 $13.42 $14.07
Netback $34.13 $23.10 $26.29 $28.43 $27.96
Natural Gas ($/Mcf)
Sales Price (1) $ 4.03 $ 2.21 $ 2.57 $ 3.32 $ 3.03
Royalties $ -- $ -- $ -- $ -- $ --
Production Expenses $ 1.09 $ 1.45 $ 1.60 $ 1.16 $ 1.33
Netback $ 2.94 $ 0.76 $ 0.97 $ 2.16 $ 1.70
Offshore West Africa Product Netbacks
Light Oil ($/bbl)
Sales Price (1) $37.86 $34.34 $37.37 $36.42 $36.47
Royalties $ 1.20 $ 0.99 $ 1.13 $ 1.03 $ 1.08
Production Expenses $14.03 $ 9.32 $ 7.11 $ 6.67 $ 8.68
Netback $22.63 $24.03 $29.13 $28.72 $26.71
Natural Gas ($/Mcf)
Sales Price (1) $ 3.80 $ 5.09 $ 4.58 $ 3.95 $ 4.37
Royalties $ 0.11 $ 0.15 $ 0.14 $ 0.11 $ 0.13
Production Expenses $ 2.37 $ 1.45 $ 1.24 $ 1.18 $ 1.39
Netback $ 1.32 $ 3.49 $ 3.20 $ 2.66 $ 2.85
NOTE: Pelican Lake oil has an API of 14 DEG. to 17 DEG., but receives medium
qualitycrude netbacks due to exceptionally low operating costs and low
royalty rates.
(1) Including transportation and excluding risk management activities
37
NETBACKS
INFORMATION BY QUARTER
YEAR 2002
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
Average Daily Production Volumes
Crude Oil and NGLs (bbls) 188,439 189,386 242,051 240,596 215,335
Natural Gas (Mcf) 1,053 1,078 1,427 1,365 1,232
Product Netbacks
Crude oil and NGLs ($/bbl)
Sales Price (1) $ 25.00 $ 30.12 $ 35.19 $ 32.83 $ 31.22
Royalties $ 2.28 $ 3.02 $ 3.56 $ 3.53 $ 3.16
Production Expenses $ 7.81 $ 7.95 $ 8.67 $ 9.10 $ 8.45
Netback $ 14.91 $ 19.15 $ 22.96 $ 20.20 $ 19.61
Natural Gas ($/Mcf)
Sales Price (1) $ 2.98 $ 3.77 $ 3.08 $ 5.07 $ 3.77
Royalties $ 0.55 $ 0.77 $ 0.67 $ 1.09 $ 0.78
Production Expenses $ 0.58 $ 0.57 $ 0.55 $ 0.57 $ 0.57
Netback $ 1.85 $ 2.43 $ 1.86 $ 3.41 $ 2.42
Crude Oil and NGL Netbacks by Type
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $ 29.09 $ 33.37 $ 38.05 $ 37.97 $ 35.16
Royalties $ 3.25 $ 4.04 $ 4.48 $ 4.39 $ 4.10
Production Expenses $ 7.48 $ 8.36 $ 10.06 $ 9.38 $ 8.97
Netback $ 18.36 $ 20.97 $ 23.51 $ 24.20 $ 22.09
Heavy ($/bbl)
Sales Price (1) $ 20.49 $ 26.42 $ 31.59 $ 26.45 $ 26.52
Royalties $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03
Production Expenses $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84
Netback $ 11.10 $ 17.08 $ 22.26 $ 15.23 $ 16.65
SEGMENTED
North America Product Netbacks
YEAR 2002
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $25.75 $31.10 $35.01 $34.34 $31.88
Royalties $ 4.24 $ 5.11 $ 5.98 $ 5.81 $ 5.35
Production Expenses $ 5.25 $ 5.30 $ 5.00 $ 5.28 $ 5.20
Netback $16.26 $20.69 $24.03 $23.25 $21.33
Heavy ($/bbl)
Sales Price (1) $20.49 $26.42 $31.59 $26.45 $26.52
Royalties $ 1.21 $ 1.86 $ 2.42 $ 2.45 $ 2.03
Production Expenses $ 8.18 $ 7.48 $ 6.91 $ 8.77 $ 7.84
Netback $11.10 $17.08 $22.26 $15.23 $16.65
Natural Gas ($/Mcf)
Sales Price (1) $ 2.96 $ 3.81 $ 3.10 $ 5.11 $ 3.79
Royalties $ 0.57 $ 0.79 $ 0.69 $ 1.11 $ 0.80
Production Expenses $ 0.56 $ 0.55 $ 0.52 $ 0.55 $ 0.55
Netback $ 1.83 $ 2.47 $ 1.89 $ 3.45 $ 2.44
North Sea Product Netbacks
Light Oil ($/bbl)
Sales Price (1) $34.43 $39.43 $42.24 $42.46 $40.32
Royalties $ 1.54 $ 1.76 $ 2.56 $ 2.79 $ 2.30
Production Expenses $10.09 $15.72 $18.30 $14.68 $15.06
Netback $22.80 $21.95 $21.38 $24.99 $22.96
Natural Gas ($/Mcf)
Sales Price (1) $ 3.77 $ 1.80 $ 1.98 $ 3.20 $ 2.75
Royalties -- -- -- -- --
Production Expenses $ 1.33 $ 1.90 $ 1.78 $ 1.25 $ 1.53
Netback $ 2.44 ($0.10) $ 0.20 $ 1.95 $ 1.22
38
Offshore West Africa Product Netbacks
YEAR 2002
------------------------------------------------------------------
1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Year Ended
----------- ----------- ----------- ----------- ----------
Light Oil ($/bbl)
Sales Price (1) $37.61 $33.92 $42.78 $43.15 $40.10
Royalties $ 1.65 $ 1.11 $ 1.34 $ 1.35 $ 1.35
Production Expenses $18.62 $12.76 $11.23 $13.68 $13.63
Netback $17.34 $20.05 $30.21 $28.12 $25.12
Natural Gas ($/Mcf)
Sales Price (1) -- -- $ 4.97 $ 4.63 $ 4.82
Royalties -- -- $ 0.15 $ 0.15 $ 0.15
Production Expenses -- -- $ 1.77 $ 1.85 $ 1.81
Netback $ -- $ -- $ 3.05 $ 2.63 $ 2.86
1) Including transportation and excluding risk management activities
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT
The following table sets forth the gross and net wells in which the Company has
participated for the period indicated:
YEAR ENDED DECEMBER 31
----------------------------
2004 2003
------------ -------------
Gross Net Gross Net
----- ---- ----- -----
Natural Gas 801 689 841 777
Crude Oil 378 328 490 458
Service/Stratigraphic 339 336 447 440
Dry Holes 106 96 126 118
---- ---- ----- -----
Total 1624 1449 1,904 1,793
==== ==== ===== =====
*Total Success Rate 91% 91%
*excluding service and stratigraphic test wells
39
G. CAPITAL EXPENDITURES
Costs incurred by the Company in respect of its programs of acquisition and
disposition, and exploration and development of crude oil and natural gas
properties, are summarized in the following tables:
YEAR ENDED
DECEMBER 31
-------------
2004 2003
----- -----
Net property acquisitions(1) 1,835 336
Land acquisition and retention 120 154
Seismic evaluation 89 77
Well drilling, completion and equipping 1,394 1,194
Pipeline and production facilities 821 522
----- -----
Reserve replacement expenditures 4,259 2,283
Midstream operations 16 11
Horizon Project 291 152
Abandonments 32 40
Head office equipment 35 20
----- -----
Total Net Capital Expenditures 4,633 2,506
===== =====
(1) Includes Business Combinations
40
2004 THREE MONTHS ENDED
--------------------------------------
($ Millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Net property acquisitions(1) 507 277 290 761
Land acquisition and retention 31 39 37 13
Seismic evaluation 32 11 25 21
Well drilling, completion and equipping 583 231 221 359
Pipeline and production facilities 280 166 190 185
----- --- --- -----
Reserve replacement expenditures 1,433 724 763 1,339
Midstream operations -- 3 2 11
Horizon Project 46 103 84 58
Abandonments 7 6 14 5
Head office equipment 7 8 12 8
----- --- --- -----
Total Net Capital Expenditures 1,493 844 875 1,421
===== === === =====
(1) Includes Business Combinations
2003 THREE MONTHS ENDED
--------------------------------------
($ Millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Net property acquisitions(1) 178 23 106 29
Land acquisition and retention 21 36 53 44
Seismic evaluation 19 21 12 25
Well drilling, completion and equipping 396 190 256 352
Pipeline and production facilities 149 107 133 133
--- --- --- ---
Reserve replacement expenditures 763 377 560 583
Midstream operations 3 1 5 2
Horizon Project 41 27 32 52
Abandonments 3 3 14 20
Head office equipment 3 2 10 5
--- --- --- ---
Total Net Capital Expenditures 813 410 621 662
=== === === ===
(1) Includes Business Combinations
41
H. NON-RESERVE ACREAGE
The following table summarizes the Company's working interest holdings in core
region non-reserve acreage as at December 31, 2004:
Gross Acres Net Acres
----------- -----------
(thousands) (thousands)
North America
Alberta 10,869 9,032
British Columbia 2,436 1,824
Saskatchewan 738 659
Manitoba 8 7
North Sea
United Kingdom 738 565
Offshore West Africa
Angola 1,220 610
Cote d'Ivoire 369 276
South Africa 5,550 5,550
------ ------
Total 21,928 18,523
====== ======
I. DEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2004:
Gross Acres Net Acres
----------- -----------
(thousands) (thousands)
North America
Alberta 5,350 3,960
British Columbia 895 682
Saskatchewan 326 242
Manitoba 6 5
North Sea
United Kingdom 138 93
Offshore West Africa
Cote d'Ivoire 8 5
----- -----
Total 6,723 4,987
===== =====
42
SELECTED FINANCIAL INFORMATION
The following table summarizes the consolidated financial statements of the
Company, which follows the full cost method of accounting for crude oil and
natural gas operations:
------------------------------------------
YEAR ENDED DECEMBER 31
------------------------------------------
2004 2003
------ ------
($ millions, except per share information)
Revenues (1) (net of royalties) 6,536 5,283
Cash flow from operations 3,769 3,160
Per common share - basic 14.06 11.77
- diluted 13.98 11.53
Net earnings (4) 1,405 1,403
Per common share - basic 5.24 5.23
- diluted 5.20 5.06
Total assets (4) 18,410 14,643
Total long-term debt(2,3) 3,538 2,748
------------------------------------------
2004 THREE MONTHS ENDED
------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (1) (net of royalties) 1,420 1,603 1,799 1,714
Net earnings 258 259 311 577
Per common share - basic 1.92 0.97 1.16 2.15
- diluted 1.92 0.97 1.13 2.13
------------------------------------------
2003 THREE MONTHS ENDED
------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (1) (net of royalties) 1,554 1,279 1,264 1,186
Net earnings (4) 427 525 201 250
Per common share - basic 1.60 1.96 0.75 0.93
- diluted 1.52 1.89 0.74 0.91
(1) Excluding transportation costs and risk management activities.
(2) Restated to include preferred securities
(3) Excluding current portion of long-term debt.
(4) Restated for asset retirement obligations
43
CAPITAL STRUCTURE
Common Shares
The Company is authorized to issue an unlimited number of common shares, without
nominal or par value. Holders of common shares are entitled to one vote per
share at a meeting of shareholders of Canadian Natural, to receive such
dividends as declared by the Board of Directors on the common shares and to
receive pro-rata the remaining property and assets of the Company upon its
dissolution or winding up, subject to any rights having priority over the common
shares.
Preferred Shares
The Company has no preferred shares outstanding, however, the Company is
authorized to issue two-hundred thousand (200,000) preferred shares designated
as Class 1 Preferred Shares. Holders of preferred shares shall not be entitled
as such to receive notice of or to attend any meeting of the shareholders of the
Company and shall not be entitled to vote at any such meeting except under
certain circumstances as described in the Articles of Amalgamation. Holders of
preferred shares are entitled to receive such dividends as and when declared by
the Board of Directors in priority to common shares and shall be entitled to
receive pro-rata in priority to holders of commons shares the remaining property
and assets of Canadian Natural upon its dissolution or winding-up. The Company
may redeem or purchase for cancellation at any time all or any part of the then
outstanding preferred shares and the holders of the preferred shares shall have
the right at any time and from time to time to convert such preferred shares
into the common shares of the company. There are no preferred shares currently
outstanding.
Credit Ratings
Credit ratings accorded to the Company's debt securities are not recommendations
to purchase, hold or sell the debt securities inasmuch as such ratings do not
comment as to market price or suitability for a particular investor. Any rating
may not remain in effect for any given period of time or may be revised or
withdrawn entirely by a rating agency in the future if in its judgment
circumstances so warrant, and if any such rating is so revised or withdrawn.
The Company's senior unsecured long-term debt securities are rated "Baa1" with a
stable outlook by Moody's Investor Services, Inc. ("Moody's"), "BBB+" by
Standard & Poor's Corporation ("S&P") and "BBB high" with a stable trend by
Dominion Bond Rating Service Limited ("DBRS"). S&P assigns a "BBB-" rating to
the Company's subordinated notes. S&P assigns a rating outlook to the Company
and not to individual debt instruments. S&P has assigned a negative outlook to
the Company.
Debt Rated
$125 CAD million 7.40% unsecured note due 2007
$400 US million 6.70% unsecured note due 2011
$400 US million 7.20% unsecured note due 2032
$350 US million 5.45% unsecured note due 2012
$350 US million 6.54% unsecured note due 2033
$125 US million 7.69% unsecured note due 2005
$93 US million 6.45% Adjustable rate note due 2009
$350 US million 4.90% unsecured note due 2014
$350 US million 5.85% unsecured note due 2035
$80 US million 8.30% subordinated note due 2011
44
Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa
to C, which represents the range from highest to lowest quality of such
securities rated. According to the Moody's rating system, debt securities rated
Baa1 are considered as medium-grade obligations, i.e. they are neither highly
protected nor poorly secured. Interest payments and principal security appear
adequate for the present but certain protective elements may be lacking or may
be characteristically unreliable over any great length of time. Such securities
lack outstanding investment characteristics and in fact have speculative
characteristics as well. Moody's applies numerical modifiers 1, 2 and 3 in each
generic rating classification from Aa through Caa in its corporate bond rating
system. The modifier 1 indicates that the issue ranks in the higher end of its
generic rating category, the modifier 2 indicates a mid-range ranking and the
modifier 3 indicates that the issue ranks in the lower end of its generic rating
category. A Moody's rating outlook is an opinion regarding the likely direction
of a rating over the medium term.
S&P's credit ratings are on a long-term debt rating scale that ranges from AAA
to D, which represents the range from highest to lowest quality of such
securities rated. According to the S&P rating system, debt securities rated BBB
exhibit adequate protection parameters. However, adverse economic conditions or
changing circumstances are more likely to lead to a weakened capacity of the
obligor to meet its financial commitments on the notes. The ratings from AA to B
may be modified by the addition of a plus (+) or minus (-) sign to show relative
standing within the major rating categories. An S&P rating outlook assesses the
potential direction of a long term credit rating over the intermediate to longer
term. In determining a rating outlook, consideration is given to any changes in
the economic and/or fundamental business conditions.
DBRS' credit ratings are on a long-term debt rating scale that ranges from AAA
to D, which represents the range from highest to lowest quality of such
securities rated. According to the DBRS rating system, debt securities rated BBB
are of adequate credit quality. Protection of interest and principal is
considered acceptable, but the entity is fairly susceptible to adverse changes
in financial and economic conditions. The assignment of a "(high)" or "(low)"
modifier within each rating category indicates relative standing within such
category. The "high" and "low" grades are not used for the AAA category. The
rating trend is DBRS' opinion regarding the outlook for the rating.
45
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES
The Company's common shares are listed and posted for trading on Toronto Stock
Exchange and the New York Stock Exchange under the symbol CNQ.
2004 Monthly Historical Trading on Toronto Stock Exchange
Month High Low Close Volume Traded
- ----- ------ ------ ------ -------------
January $71.80 $63.82 $64.00 12,121,445
February 73.85 63.99 73.25 9,749,239
March 76.50 70.20 72.70 12,853,959
April 81.65 72.85 75.40 12,279,432
May 1 - 18 81.70 73.80 78.55 8,416,911
*May 19 - 31 39.40 35.08 37.00 12,306,037
June 41.15 35.26 40.05 27,235,021
July 44.27 39.75 44.25 16,359,717
August 45.45 40.52 42.71 22,497,977
September 51.04 41.75 50.50 26,159,733
October 55.15 48.61 51.28 27,437,454
November 52.33 45.90 51.03 31,361,601
December 51.90 45.50 51.25 28,812,709
* Shares began trading on a post two-for-one subdivision basis on May 19,
2004.
On January 21, 2002, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, beginning January 23, 2002 and ending January 22, 2003, to
purchase for cancellation up to 6,060,180 common shares of the Company, being 5
per cent of the 121,203,603 common shares of the Company outstanding on January
18, 2002. No common shares were purchased during this program.
In January 2002, the Company issued 60,000 flow-through common shares at a price
of $39.00 per common share. The value of the common shares was determined as the
closing market price on Toronto Stock Exchange on the day prior to the allotment
of the common shares.
On January 22, 2003, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, beginning January 24, 2003 and ending January 23, 2004, to
purchase for cancellation up to 6,692,799 common shares of the Company, being 5
per cent of the 133,855,988 common shares of the Company outstanding on January
17, 2003. Under this program, the Company purchased a total of 2,734,800 common
shares for cancellation at an average purchase price of $52.51 for each common
share purchased.
On January 22, 2004, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, commencing January 24, 2004 and ending January 23, 2005, to
purchase for cancellation up to 6,690,385 common shares of the Company, being 5
per cent of the 133,807,695 common shares of the Company outstanding on January
13, 2004. Under this program, the Company purchased a total of 873,400 common
shares for cancellation at an average purchase price of $37.98 for each common
share purchased; $38.01 after costs.
46
At the Annual and Special Meeting of Shareholders held May 6, 2004, the
shareholders passed a special resolution amending the Articles of the Company to
divide the issued and outstanding Common Shares on a two-for-one basis. The
subdivision of the Common Shares occurred on May 21, 2004.
On January 20, 2005, the Company announced its intention to make a Normal Course
Issuer Bid through the facilities of Toronto Stock Exchange and the New York
Stock Exchange, commencing January 24, 2005 and ending January 23, 2006, to
purchase for cancellation up to 13,409,006 common shares of the Company, being 5
per cent of the 268,180,123 common shares of the Company outstanding on January
12, 2005. As of the date of this Annual Information Form, no shares have been
purchased.
On March 9, 2005, the Board of Directors passed a resolution proposing an
amendment to the Articles of the Company to sub-divide the issued and
outstanding Common Shares of the Company on a two-for-one basis subject to
shareholder approval at the Annual and Special Meeting of Shareholders scheduled
for May 5, 2005.
DIVIDEND HISTORY
The dividend policy of the Company undergoes a periodic review by the Board of
Directors and is subject to change at any time depending upon the earnings of
the Company, its financial requirements and other factors existing at the time.
Prior to 2001, dividends had not been paid on the common shares of the Company.
On January 17, 2001 the Board of Directors approved a dividend policy for the
payment of a regular quarterly dividend of $0.10 per common share. Dividends
have been paid on the first day of January, April, July and October of each year
since 2001.
The following table restated for the two-for-one subdivision of the common
shares which occurred in May 2004 shows the aggregate amount of the cash
dividends declared per common share of the Company and accrued in each of its
last three years ended December 31.
2004 2003 2002
----- ----- -----
Cash dividends declared per common share $0.40 $0.30 $0.25
TRANSFER AGENTS AND REGISTRAR
The Company's transfer agent and registrar for its common shares is
Computershare Trust Company of Canada in the cities of Calgary and Toronto and
Computershare Shareholder Services, Inc. in the city of New York. The registers
for transfers of the Company's common shares are maintained by Computershare
Trust Company of Canada.
47
DIRECTORS AND EXECUTIVE OFFICERS
The names, municipalities of residence, offices held with the Company and
principal occupations of the directors and officers of the Company are set forth
below:
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
- ---- ----------------------- ----------------------------------------
Catherine M. Best Director(2)(4) Executive Vice-President, Risk Management and Chief
Calgary, Alberta (age 51) Financial Officer of the Calgary Health Region from 2002
Canada to present, Vice-President, Corporate Services and Chief
Financial Officer of the Calgary Health Region from
February 2000 to 2002; prior thereto with Ernst & Young
since 1980, most recently as a Corporate Audit Partner
from 1991 to 2000. Has served continuously as a director
since November 2003.
N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private
Calgary/Banff, Alberta Director(3)(5) management and consulting company). Has served
Canada (age 45) continuously as a director of the Company since September
1988. Currently serving on the board of directors of
Ensign Resource Service Group Inc.; Magellan Aerospace
Corporation; and, Penn West Petroleum Ltd.
Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm)
Atlanta, Georgia (age 55) since May 2001; prior thereto United States Ambassador to
USA Canada. Has served continuously as a director of the
Company since May 2002. Currently serving on the board of
directors of Bowater, Inc.; Canadian National Railway;
Canadian Imperial Bank of Commerce; and, Transalta
Corporation.
John G. Langille President and Director Officer of the Company. Has served continuously as a
Calgary, Alberta (age 59) director of the Company since June 1982.
Canada
Keith A.J. MacPhail Director(3)(4)(5) Chairman, President and Chief Executive Officer, Bonavista
Calgary, Alberta (age 48) Petroleum Ltd. (independent oil and natural gas company)
Canada since November 1997 and Chairman, NuVista Energy Ltd since
July 2003. Has served continuously as a director of the
Company since October 1993. Currently serving on the board
of directors of Bonavista Petroleum Ltd., Bonavista Energy
Trust and NuVista Energy Ltd.
Allan P. Markin Chairman and Chairman of the Company. Has served continuously as a
Calgary, Alberta Director(3)(5) director of the Company since January 1989.
Canada (age 59)
James S. Palmer, C.M., A. O. Director(3)(4)(5) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has
E., Q.C. (age 76) served continuously as a director of the Company since May
Calgary, Alberta 1997. Currently serving on the board of directors of
Canada Magellan Aerospace Corporation; Trenton Iron Works; Rally
Energy Corp.; and, on the board of trustees for Rogers
Sugar Income Fund.
Dr. Eldon R. Smith, M.D. Director(1)(4)(5) Emeritus Professor and Former Dean, Faculty of Medicine,
Calgary, Alberta (age 65) University of Calgary. Has served continuously as a
Canada director of the Company since May 1997. Currently serving
on the board of directors of Vasogen Inc.; and, Pheromone
Sciences Corp.
48
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
- ---- ----------------------- ----------------------------------------
David A. Tuer Director(1)(2)(3) An independent businessman. Chairman, Calgary Health
Calgary, Alberta (age 55) Region since October 2001 and President and CEO of Hawker
Canada Resources Inc. (independent oil and natural gas company)
from January 2003 to March 2005. Prior thereto President
and Chief Executive Officer, PanCanadian Energy
Corporation. Has served continuously as a director of the
Company since May 2002. Currently serving on the board of
directors of Rockwater Capital Corporation; and, Argo
Energy Ltd.
Steve W. Laut Chief Operating Officer Officer of the Company.
Calgary, Alberta (age 47)
Canada
Real M. Cusson Senior Vice-President, Officer of the Company.
Calgary, Alberta Marketing
Canada (age 54)
Real J. H. Doucet Senior Vice-President, Officer of the Company since October 2000; prior thereto
Calgary, Alberta Oil Sands director of various divisions at Suncor Inc. since 1993.
Canada (age 52)
Allen M. Knight Senior Vice-President, Officer of the Company.
Calgary, Alberta International &
Canada Corporate Development
(age 55)
Tim S. McKay Senior Vice-President, Officer of the Company.
Calgary, Alberta Operations
Canada (age 43)
Douglas A. Proll Senior Vice-President, Officer of the Company since April 2001; prior thereto
Calgary, Alberta Finance Vice President Finance and Treasurer of Renaissance Energy
Canada (age 54) Ltd. to August 2000 and most recently Vice President
Finance and Business Development of Husky Energy Inc. from
August 2000 to February 2001.
Lyle G. Stevens SeniorVice-President, Officer of the Company.
Calgary, Alberta Exploitation
Canada (age 50)
Jeffrey W. Wilson Senior Vice-President, Officer of the Company since September 2003; prior thereto
Calgary, Alberta Exploration Exploration Manager of the Company.
Canada (age 52)
Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto
Calgary, Alberta (age 46) Co-ordinator Land at PanCanadian Petroleum Limited to 1999
Canada and most recently Manager Commercial Ventures and Land at
PanCanadian Petroleum Limited 1999 to 2002.
William R. Clapperton Vice-President, Officer of the Company since January 2002; prior thereto
Calgary, Alberta Regulatory, Stakeholder Manager, Surface Land and Environment for the Company.
Canada and Environmental
Affairs (age 42)
Gordon M. Coveney Vice-President, Officer of the Company since September 2003; prior thereto
Calgary, Alberta Exploration, Northeast Exploration Manager for the Company.
Canada District
(age 51)
Randall S. Davis Vice-President, Officer of the Company since July 2004; prior thereto
Calgary, Alberta Financial Accounting Manager, Financial Reporting of the Company to July 2002
Canada and Controls (age 38) and most recently Financial Controller of the Company from
July 2002 to July 2004.
49
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
- ---- ----------------------- ----------------------------------------
Jerome W. Harvey Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Commercial Operations Manager, Commercial Operations.
Canada (age 51)
Peter Janson Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Engineering Integration Director, Production Planning and Control to June 2000 and
Canada (age 47) Director, Health and Safety and Environment from June 2000
to November 2002 at Suncor Oil Sands and most recently
Director, Engineering Integration of the Company from
November 2002 to December 2004.
Terry J. Jocksch Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Exploitation East Exploitation Manager of the Company to April 2004.
Canada (age 37)
Christopher M. Kean Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Utilities and Offsite, Manager Facilities Engineering to January 2002, Utilities
Canada Horizon Oil Sands and Offsites Project Manager January 2002 to July 2002,
Project Director, Utilities and Offsites July 2002 to July 2003
(age 41) and most recently General Manager, Utilities and Offsites
July 2003 to December 2004.
Philip A. Keele Vice-President, Mining, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Horizon Oil Sands from Mine Manager at Fording Coal Limited to February
Canada Project 2001, Chief Mine Engineer of the Company February 2001 to
(age 45) September 2002 and most recently Director, Mine
Engineering of the Company from September 2002 to December
2004.
Cameron S. Kramer Vice-President, Officer of the Company since September 2002; prior thereto
Calgary, Alberta Field Operations Production Engineer of the Company to March 2000 and most
Canada (age 37) recently Manager, Field Operations of the Company from
April 2000 to September 2002.
Leon Miura Vice-President, Officer of the Company since August 2003; prior thereto
Calgary, Alberta Upgrading held progressively senior positions at Petroleos de
Canada (age 50) Venezuela including Cerro Negro Execution Manager, Heavy
Oil Upgrading from 1997 to 2001 and most recently Nitrogen
Injection Project Director, Secondary Recovery at
Petroleos de Venezuela 2002 to 2003.
John S. J. Parr Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Production, East Production Engineer, NE Gas of the Company to July 2001,
Canada (age 43) Manager, Production Engineering of the Company from July
2002 to June 2002 and most recently Production Manager,
Heavy Oil of the Company from July 2002 to April 2004.
David A. Payne Vice-President, Officer of the Company since October 2004; prior thereto
Calgary, Alberta Exploitation, West Exploitation Manager, Thermal Heavy of the Company to
Canada (age 43) July 2000, Director, Exploitation of CNR International
(U.K.) Limited a wholly-owned subsidiary of the Company
from July 2000 to August 2003 and most recently
Exploitation Manager, Technical Projects of the Company
from August 2003 to October 2004.
William R. Peterson Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Production, West Production Manager, West of the Company.
Canada (age 38)
John C. Puckering Vice President, Site Officer of the Company since April 2004; prior thereto
Calgary, Alberta Development General Manager DCL Construction Inc. to November 2001,
Canada (age 58) President of 960925 Alberta Ltd. from November 2001 to
April 2002, Manager, Site Development of the Company May
2002 to December 2002 and most recently General Manager
Site Development of the Company from January 2003 to April
2004.
50
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
- ---- ----------------------- ----------------------------------------
Sheldon L. Schroeder Vice-President, Project Officer of the Company since April 2004; prior thereto
Calgary, Alberta Control engineer with 729248 Alberta Ltd. to June 2001, Project
Canada (age 37) Control Manager of the Company from June 2001 to
September 2002 and most recently Director, Project Control
of the Company from September 2002 to April 2004.
Kendall W. Stagg Vice-President, Officer of the Company since October 2004; prior thereto
Calgary, Alberta Exploration, West Cardium Geophysicist of the Company to April 2001, Chief
Canada (age 43) Geophysicist of the Company from April 2001 to June 2002
and most recently Manager Exploration, B. C. of the
Company from June 2002 to September 2004.
Lynn M. Zeidler Vice-President, Bitumen Officer of the Company since August 2003; prior thereto
Calgary, Alberta Production held progressively senior positions at Shell Canada
Canada (age 48) Limited including on secondment from Shell Canada Limited
as Manager-Tier 1 Implementation at Sable Offshore Energy
Inc to September 2000 and most recently General Project
Manager, Athabasca Oil Sands Project at Shell Canada
Limited October 2000 to May 2003 and concurrently as Vice
President & Project Director, Muskeg River Mine at Albian
Sands Energy Inc. May 2002 to July 2003 and General
Manager Claims Athabasca Oil Sands Project at Shell Canada
Limited May 2003 to July 2003.
Kimberly I. McKay Treasurer Officer of the Company since December 2004; prior thereto
Calgary, Alberta (age 36) Financial Accountant of the Company to October 2001,
Canada Advisor Capital Markets and Treasury Administration of the
Company from October 2001 to July 2002 and most recently
Treasury Manager of the Company from July 2002 to December
2004.
Bruce E. McGrath Corporate Secretary Officer of the Company.
Calgary, Alberta (age 55)
Canada
(1) Member of the Nominating and Corporate Governance Committee
(2) Member of the Audit Committee
(3) Member of the Reserves Committee
(4) Member of the Compensation Committee
(5) Member of the Safety, Health and Environmental Committee
All directors stand for election at each Annual General Meeting of CNRL
shareholders. All of the current directors were elected to the Board at the last
annual meeting of shareholders held on May 6, 2004. All of the current directors
are standing for election at the Annual General Meeting of Shareholders
scheduled for May 5, 2005.
As at December 31, 2004, the directors and officers of the Company, as a group,
beneficially owned, directly or indirectly, or exercised control or direction
over, in the aggregate, approximately 4 per cent of the total outstanding common
shares (approximately 5 per cent after the exercise of options held by them
pursuant to the Company's stock option plan).
Conflicts of Interest
There are potential conflicts of interest to which the directors and officers of
the Company may become subject in connection with the operations of the Company.
Some of the directors and officers have been and will continue to be engaged in
the identification and evaluation of businesses and assets with a view to
potential acquisition of interests on their own behalf and on
51
behalf of other corporations, and situations may arise where the directors and
officers will be in direct competition with the Company. Conflicts, if any, will
be subject to the procedures and remedies under the Business Corporations Act
(Alberta).
AUDIT COMMITTEE INFORMATION
Audit Committee Members
The Audit Committee of the Board of Directors of the Company is comprised of Ms.
C. M. Best, Chair, Messrs. G. D. Giffin and D. A. Tuer each of whom is (i)
independent as defined under Canadian securities regulations NI 52-110 and the
NYSE listing standards as they pertain to audit committees of listed issuers;
and, (ii) financially literate.
Ms. C. M. Best is a chartered accountant with 20 years experience as a staff
member and partner of an international public accounting firm. During her tenure
she was responsible for direct oversight and supervision of a large staff of
auditors conducting audits of the financial reporting of significant publicly
traded entities, many of which were oil and gas companies. This oversight and
supervision required Ms. C. M. Best to maintain a current understanding of
generally accepted accounting principles, and be able to assess their
application in each of her clients. It also required an understanding of
internal controls and financial reporting processes and procedures.
Ambassador G. D. Giffin's education and experience relevant to the performance
of his responsibilities as an audit committee member is derived from a thirty
year law practice involving complex accounting and audit-related issues
associated with complicated commercial transactions and disputes. He has
developed extensive practical experience and an understanding of internal
controls and procedures for financial reporting from his service on audit
committees for several publicly traded issuers and continues pursuit of
extensive professional reading and study on related subjects.
Mr. D. A. Tuer's education and experience relevant to the performance of his
responsibilities as an audit committee member is derived from professional
training and a business career as a Chief Executive Officer in a large publicly
traded company which provided experience in analyzing and evaluating financial
statements and supervising persons engaged in the preparation, analysis and
evaluation of financial statements of publicly traded companies. He has gained
an understanding of internal controls and procedures for financial reporting
through oversight of those functions, and the understanding of Audit Committee
functions through his years of Chief Executive involvement.
Auditor Service Fees
Auditor Service 2004 2003
- --------------- ---------- --------
Audit fees $1,100,548 $886,000
Audit related fees $ 183,663 $ 12,500
Tax related fees $ 39,330 $ 11,000
All other fees $ 0 $ 10,000
52
LEGAL PROCEEDINGS
From time to time, CNRL is the subject of litigation arising out of the
Company's operations. Damages claimed under such litigation may be material or
may be indeterminate and the outcome of such litigation may materially impact
the Company's financial condition or results of operations. While the Company
assesses the merits of each lawsuit and defends itself accordingly, the Company
may be required to incur significant expenses or devote significant resources to
defend itself against such litigation. The claims that have been made to date
are not currently expected to have a material impact on the Company's financial
position.
INTERESTS OF EXPERTS
Canadian Natural's auditor is PricewaterhouseCoopers LLP, Chartered Accountants,
3100, 111-5th Avenue S. W. Calgary, Alberta T2P 5L3. The Company's audited
consolidated financial statements for the year ended December 31, 2004 have been
filed under National Instrument 51-102 in reliance on the report of
PricewaterhouseCoopers LLP, independent chartered accountants, given on their
authority as experts in auditing and accounting.
Sproule Associates Limited, Ryder Scott Company and Gilbert Laustsen Jung
Associates Ltd. have provided the Report on Reserves Data attached as Schedule
"A" to this Annual Information Form in their capacity as the Company's
Independent Qualified Reserves Evaluators. Sproule Associates Limited, Ryder
Scott Company and Gilbert Laustsen Jung Associates Ltd. and their directors,
officers and associates, collectively own less than 1% of the Company's
outstanding common shares.
ADDITIONAL INFORMATION
Additional information relating to the Company can be found on the SEDAR website
at www.sedar.com
Additional information including Directors' and Executive Officers' remuneration
and indebtedness, principal holders of the Company's securities, options to
purchase the Company's securities and interest of insiders in material
transactions is contained in the Company's Notice of Annual and Special Meeting
and Information Circular dated March 17, 2005 in connection with the Annual and
Special Meeting of Shareholders of Canadian Natural to be held on May 5, 2005
which information is incorporated herein by reference. Additional financial
information and discussion of the affairs of the Company and the business
environment in which the Company operates is provided in the Company's
Management Discussion and Analysis, comparative Consolidated Financial
Statements and Supplementary Oil & Gas Information for the most recently
completed fiscal year ended December 31, 2004 found on pages 39 to 67, 68 to 90
and 91 to 95 respectively, of the 2004 Annual Report to the Shareholders, which
information is incorporated herein by reference.
For additional copies of this Annual Information Form, please contact:
Corporate Secretary of the Corporation at:
2500, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8
53
SCHEDULE "A"
Amended Form 51-101F2
Report on Reserves Data by
Independent Qualified Reserves Evaluator or Auditor
Report on Reserves Data
To the Board of Directors of Canadian Natural Resources Limited (the
"Corporation"):
1. Except as noted in 1(c) (i), we have evaluated the Corporation's reserves
data as at December 31, 2004. The reserves data consist of the following:
(a) (i) proved oil and natural gas reserve quantities estimated as at December
31, 2004 using constant prices and costs;
(ii) the related estimated future net revenue; and
(iii) the related standardized measure calculation for proved oil and
natural gas reserve quantities.
(b) (i) proved and proved plus probable oil and natural gas reserves estimated
as at December 31, 2004 using forecast prices and costs; and (ii) the
related estimated future net revenue
(c) (i) proved and proved plus probable bitumen and synthetic crude oil
reserves relating to surface mineable oil sands projects estimated as
at February 9, 2005
2. The reserves data are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on the reserves data based on
our evaluation.
3. We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
Society) with the necessary modifications to reflect definitions and
standards under the U.S. Financial Accounting Standards Board policies (the
"FASB Standards") and the legal requirements of the U.S. Securities and
Exchange Commission ("SEC Requirements").
4. Those standards require that we plan and perform an evaluation to obtain
reasonable assurance as to whether the reserves data are free of material
misstatement. An evaluation also includes assessing whether the reserves
data are in accordance with principles and definitions as outlined above.
5. The following table sets forth the estimated net present value of future
cash flows (before deduction of income taxes) attributed to proved oil and
natural gas reserves quantities, estimated using constant prices and costs
and calculated using a discount rate of 10 percent, included in the
reserves data of the Corporation evaluated by us for the year ended
December 31, 2004 except as noted in 1(c)(i), and identifies the respective
portions
54
thereof that we have evaluated and reported on to the Corporation's management
and board of directors:
- ----------------------------------------------------------------------------------------------------
Independent Description and Location of Net Present Values of Future Cash Flows
Qualified Preparation Reserves (Country (Before Income Taxes, 10% Discount Rate)
Reserves Date of or Foreign --------------------------------------------
Evaluator or Evaluation Geographic Audited Evaluated Reviewed Total
Auditor Report Area) MM$ MM$ MM$ MM$
- ----------------------------------------------------------------------------------------------------
Sproule Sproule Canada, USA $0 $11,242.36 $0 $11,242.36
Associates Ltd. Evaluated the
P&NG
Reserves as
reported
February 18,
2005.
- ----------------------------------------------------------------------------------------------------
Ryder Scott Ryder Scott Canada (assets $0 $ 468.00 $0 $ 468.00
Company Evaluated the acquired November
P&NG Reserves 2004)
as reported
February 18,
2005.
- ----------------------------------------------------------------------------------------------------
Ryder Scott Ryder Scott United Kingdom $0 $ 6,427.80 $0 $ 6,427.80
Company Evaluated the and Offshore West
P&NG Reserves Africa
as reported
February 18,
2005.
- ----------------------------------------------------------------------------------------------------
Totals $0 $18,138.16 $0 $18,138.16
- ----------------------------------------------------------------------------------------------------
In addition all proved and proved plus probable company gross reserves have been
evaluated for oil sands mining properties located in Canada. Horizon mining
reserves are not part of Canadian Natural's year end. The Horizon reserves were
evaluated as at February 9th, 2005. Gilbert Laustsen Jung Associates Ltd
("GLJ"), an independent qualified reserves evaluator, was retained by the
Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves
associated with the Horizon Project incorporating both the mining and upgrading
projects. These reserves were evaluated under SEC Industry Guide 7 and are
discussed separately from the Company's conventional oil and gas activities.
6. In our opinion, the reserves data respectively evaluated by us have, in all
material respects, been determined and are in accordance with the COGE
Handbook as modified by the FASB Standards and SEC requirements. We express
no opinion on the reserves data that we reviewed but did not audit or
evaluate.
55
7. We have no responsibility to update our evaluation for events and
circumstances occurring after their respective preparation dates.
8. Reserves are estimates only, and not exact quantities. In addition, as the
reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.
Executed as to our report referred to above:
February 18, 2005
SPROULE ASSOCIATES LIMITED
Original Signed By:
/s/ Harry J. Helwerda
------------------------------------
Harry J. Helwerda, P.Eng.,
Vice-President, Engineering,
Original Signed By:
/s/ Doug Ho
------------------------------------
Doug Ho, P.Eng.
Manager, Engineering, and Associate
Original Signed By:
/s/ Ken H. Crowther
------------------------------------
Ken H. Crowther, P.Eng.
President, Canada and U.S.
RYDER SCOTT COMPANY
Original Signed By:
/s/ Jane Tink
------------------------------------
Jane Tink, P.Eng.,
Vice-President, Engineering
GILBERT LAUSTSEN JUNG ASSOCIATES LTD.
Original Signed By:
/s/ James H. Willmon
------------------------------------
James H. Willmon, P.Eng.
Vice-President
56
SCHEDULE "B"
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
Report of Management and Directors on Reserves Data and Other Information
Management of Canadian Natural Resources Limited (the "Corporation") is
responsible for the preparation and disclosure of information with respect to
the Corporation's oil and natural gas and surface mineable oil sands activities
in accordance with securities regulatory requirements. This information includes
reserves data, which consist of the following:
(a) (i) proved oil and natural gas reserve quantities estimated as at December
31, 2004 using constant prices and costs;
(ii) the related estimated future net revenue; and
(iii)the related standardized measure calculation for proved oil and
natural gas reserve quantities.
(b) (i) proved and proved plus probable oil and natural gas reserves estimated
as at December 31, 2004 using forecast prices and costs;
(ii) the related estimated future net revenue; and,
(c) (i) proved and probable working interest oil reserve quantities relating
to surface mineable oil sands operations estimated as at February 9,
2005.
Sproule Associates Limited, Ryder Scott Company and Gilbert Laustsen Jung
Associates Ltd. all independent qualified reserves evaluators have evaluated the
Corporation's reserves data. The report of the independent qualified reserves
evaluator will be filed with securities regulatory authorities concurrently with
this report.
The reserves committee (the "Reserves Committee") of the board of directors (the
"Board of Directors") of the Corporation has:
(a) reviewed the Corporation's procedures for providing information to the
independent qualified reserves evaluator;
(b) met with each of the independent qualified reserves evaluators to
determine whether any restrictions placed by management affected the
ability of the independent qualified reserves evaluators to report
without reservation; and
(c) reviewed the reserves data with management and the independent
qualified reserves evaluators.
57
The Reserves Committee of the Board of Directors has reviewed the Corporation's
procedures for assembling and reporting other information associated with oil
and natural gas activities and has reviewed that information with management.
The Board of Directors has, on the recommendation of the Reserves Committee,
approved:
(a) the content and filing with securities regulatory authorities of the
reserves data and other oil and natural gas and surface mineable oil
sands information;
(b) the filing of the reports of the independent qualified reserves
evaluators on the reserves data; and
(c) the content and filing of this report.
Reserves data are estimates only, and are not exact quantities. In
addition, as the reserves data are based on judgments regarding future
events, actual results will vary and the variations may be material.
"Signed"
Steve W. Laut
Chief Operating Officer
"Signed"
Douglas A. Proll
Senior Vice President, Finance
"Signed"
David A. Tuer
Independent Director and Chair of the Reserve Committee
"Signed"
Keith A.J. MacPhail
Independent Director and Member of the Reserve Committee
Dated this 18th day of February, 2005
Calgary, Alberta