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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 40-F
[_] Registration Statement pursuant to section 12 of the Securities
Exchange Act of 1934
[X] Annual report pursuant to section 13(a) or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2005 Commission File Number: 1-8795
CANADIAN NATURAL RESOURCES LIMITED
(Exact name of Registrant as specified in its charter)
ALBERTA
(Province or other jurisdiction of incorporation or organization)
1311
(Primary Standard Industrial Classification Code Numbers)
NOT APPLICABLE
(I.R.S. Employer Identification Number (if applicable))
2500, 855-2ND STREET S.W., CALGARY, ALBERTA, CANADA, T2P 4J8
TELEPHONE: (403) 517-7345
(Address and telephone number of Registrant's principal executive offices)
CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK, NEW YORK 10011
(212) 894-8940
(Name, address (including zip code) and telephone
number (including area code) of agent for
service in the United States)
SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS: ON WHICH REGISTERED:
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Common Shares, no par value New York Stock Exchange
Toronto Stock Exchange
SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO
SECTION 12(G) OF THE ACT:
TITLE OF EACH CLASS: None
SECURITIES FOR WHICH THERE IS A REPORTING OBLIGATION PURSUANT TO
SECTION 15(D) OF THE ACT: None
FOR ANNUAL REPORTS, INDICATE BY CHECK MARK THE INFORMATION FILED WITH THIS FORM:
[X] Annual information form [X] Audited annual financial statements
NUMBER OF OUTSTANDING SHARES OF EACH OF THE ISSUER'S CLASSES
OF CAPITAL OR COMMON STOCK AS OF THE CLOSE OF THE PERIOD
COVERED BY THE ANNUAL REPORT.
536,347,796 Common Shares outstanding as of December 31, 2005
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Indicate by check mark whether the Registrant is furnishing the information
contained in this Form to the Commission pursuant to Rule 12g3-2(b) under the
Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked,
indicate the filing number assigned to the Registrant in connection with such
Rule.
Yes [_] No [X]
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Exchange Act during the
preceding 12 months (or for such shorter period that the Registrant was
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [_]
This Annual Report on Form 40-F shall be incorporated by reference into, or as
an exhibit to, as applicable, the registrant's Registration Statement on Form
F-9 (Registration No. 333-104919) under the Securities Act of 1933.
PRINCIPAL DOCUMENTS
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The following documents have been filed as part of this Annual Report on Form
40-F, starting on the following page:
A. ANNUAL INFORMATION FORM
Annual Information Form of Canadian Natural Resources Limited
("Canadian Natural") for the year ended December 31, 2005.
B. AUDITED ANNUAL FINANCIAL STATEMENTS
Canadian Natural's audited consolidated financial statements for the
years ended December 31, 2005 and 2004, including the auditor's
report with respect thereto. For a reconciliation of important
differences between Canadian and United States generally accepted
accounting principles, see Note 15 of the Notes to the Consolidated
Financial Statements.
C. MANAGEMENT'S DISCUSSION AND ANALYSIS
Canadian Natural's Management's Discussion and Analysis for the year
ended December 31, 2005.
SUPPLEMENTARY OIL & GAS INFORMATION
For Canadian Natural's Supplementary Oil & Gas Information for the year ended
December 31, 2005, see Exhibit 1 of this Annual Report on Form 40-F.
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C A N A D I A N N A T U R A L R E S O U R C E S L I M I T E D
ANNUAL INFORMATION FORM
MARCH 29, 2006
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1
TABLE OF CONTENTS
DEFINITIONS..................................................................3
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS............................5
THE COMPANY..................................................................7
GENERAL DEVELOPMENT OF THE BUSINESS..........................................8
REGULATORY MATTERS..........................................................11
RISK FACTORS................................................................12
ENVIRONMENTAL MATTERS.......................................................16
DESCRIPTION OF THE BUSINESS.................................................16
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES..............18
DRILLING ACTIVITY..................................................19
PRODUCING CRUDE OIL AND NATURAL GAS WELLS..........................20
NORTHEAST BRITISH COLUMBIA.........................................20
NORTHWEST ALBERTA..................................................21
NORTHERN PLAINS....................................................22
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN.........................25
HORIZON OIL SANDS PROJECT..........................................26
UNITED KINGDOM NORTH SEA...........................................28
OFFSHORE WEST AFRICA...............................................29
COTE D'IVOIRE......................................................30
ANGOLA.............................................................31
GABON..............................................................31
B. CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES...................32
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES.................37
D. OIL SANDS MINING DISCLOSURE............................................38
E. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION.............................45
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT................................50
G. CAPITAL EXPENDITURES...................................................51
H. UNDEVELOPED ACREAGE....................................................53
I. DEVELOPED ACREAGE......................................................53
SELECTED FINANCIAL INFORMATION..............................................54
2
CAPITAL STRUCTURE...........................................................55
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES....................57
DIVIDEND HISTORY............................................................58
TRANSFER AGENTS AND REGISTRAR...............................................58
DIRECTORS AND OFFICERS......................................................59
CONFLICTS OF INTEREST.......................................................63
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS..................63
AUDIT COMMITTEE INFORMATION.................................................63
LEGAL PROCEEDINGS...........................................................65
MATERIAL CONTRACTS..........................................................65
INTERESTS OF EXPERTS........................................................65
ADDITIONAL INFORMATION......................................................65
SCHEDULE "A" REPORT ON RESERVES DATA........................................67
SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS.............................70
SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE.................................72
CURRENCY
Unless otherwise indicated, all dollar figures stated in this Annual Information
Form represent Canadian dollars.
3
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.
"BBL/D" means barrels per day.
"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", 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.
"CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS" includes all of the Company's
light and medium crude oil, heavy crude oil, thermal in-situ, natural gas,
coal bed methane and natural gas liquid activities. It does not include the
Company's oil sands mining assets.
"DEVELOPMENT WELL" means a well drilled into a zone that is known to be
productive and expected to produce crude oil or natural gas in the future.
"DRY WELL" means a well drilled that is not capable of producing commercial
quantities of crude oil or natural gas to justify completion. A dry well will
be plugged back, abandoned and reclaimed.
"EXPLORATORY WELL" means a well drilled into an unproven territory with the
intention to discover commercial quantities of crude oil or natural gas.
"FPSO" means a 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.
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"NET WELLS" refers to gross wells multiplied by the percentage working
interest therein owned or to be owned by the Company.
"PRODUCTIVE WELL" a well that is not dry.
"SAGD" means steam-assisted gravity drainage.
"UNDEVELOPED 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.
5
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 Securities 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 "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; political uncertainty, including actions of or against
terrorists or 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; the 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 ability of the Company to attract the necessary
labour required to build its projects; the operating hazards and other
difficulties inherent in the exploration for and production and sale of crude
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 asset
retirement obligations; 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 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 were 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. Except as required by law, 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
6
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 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.
For the year ended December 31, 2005, Canadian Natural retained qualified
independent reserve evaluators, Sproule Associates Limited ("Sproule") and
Ryder Scott Company ("Ryder Scott"), to evaluate 100% of the Company's
conventional proved and probable crude oil, natural gas liquid ("NGL") and
natural gas reserves and prepare Evaluation Reports on these reserves. Sproule
evaluated the Company's North American conventional assets and Ryder Scott
evaluated its conventional international assets. The Company has been granted
an exemption from the 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. There are two principal differences
between the two standards. The first is the additional requirement under NI
51-101 to disclose both proved and proved and probable reserves, as well as
the related net present value of future net revenues using forecast prices and
costs. The second is in the definition of proved reserves; however, as
discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the
standards that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.
The Company has disclosed conventional proved reserves and the Standardized
Measure of discounted future net cash flows using constant prices and costs as
mandated by the SEC in the supplementary oil and gas information section of
its Annual Report. The Company has also elected to provide the net present
value of these same conventional proved reserves as well as the conventional
proved and probable reserves and the net present value of these reserves under
the same parameters as additional voluntary information. In addition to the
constant price and cost scenario, the Company has also elected to provide both
conventional proved and conventional proved and probable reserves, as well as
the net present value of these reserves, using forecast prices and costs as
voluntary additional information.
Reserves and net present values of these reserves 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.
For the year ended December 31, 2005, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants ("GLJ"), to evaluate
100% of phases 1 through 3 of the Company's Horizon Oil Sands Project and
prepare an Evaluation Report on the Company's proved, as well as proved and
probable oil sands mining reserves incorporating both the mining and upgrading
projects. These reserves were evaluated adhering to the requirements of SEC
Industry Guide 7 using year-end constant pricing and have been disclosed
separately from the Company's conventional crude oil, NGL and natural gas
reserves.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule, Ryder
Scott and GLJ to review the qualifications of and procedures used by each
7
evaluator in determining the estimate of the Company's quantities and net
present value of remaining conventional crude oil, NGL and natural gas
reserves, as well as the Company's quantity of oil sands mining reserves.
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, adjusted net
earnings 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. 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.
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. Canadian Natural 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.
Canadian Natural 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 ("Ranger"), including its
subsidiaries, 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.
8
The significant operating subsidiaries of the Company, each of which is
directly or indirectly wholly-owned, and their jurisdictions of incorporation
are as follows:
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JURISDICTION
NAME OF COMPANY OF INCORPORATION
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CanNat Energy Inc. Delaware
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
CNR International (Gabon) Limited Bahamas
Horizon Construction Management Ltd. Alberta
Renata Resources Inc. Alberta
Canadian Natural, as the managing partner, 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, CNR
(ECHO) Resources Inc., Renata Resources Inc., and Canadian Natural are
partners of Canadian Natural Resources Northern Alberta Partnership, a general
partnership. The two partnerships hold the majority of the producing Canadian
crude oil and natural gas properties of Canadian Natural. The Company also has
a 15 per cent interest in Cold Lake Pipeline Ltd., which is the general
partner of Cold Lake Pipeline Limited Partnership in which Canadian Natural
holds a separate 14.7 per cent partnership interest. Canadian Natural, 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. Canadian Natural, as the managing
partner, and 1081840 Alberta Ltd. are the partners of 1081840 Alberta
Partnership, which holds certain crude oil and natural gas properties of the
Company.
The consolidated financial statements of Canadian Natural include the accounts
of the Company and all of its subsidiaries and partnerships.
GENERAL DEVELOPMENT OF THE BUSINESS
Canadian Natural'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. Canadian Natural'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, 2005 the Company had 2,580
permanent employees in North America and 317 permanent employees in its
international operations.
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
9
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 crude 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 crude 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 mmcf/d of natural gas and 200
bbl/d of light crude oil and NGLs and contained 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 mmcf/d 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 has added 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 crude 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 crude 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 mmcf/d of natural gas and 7.5 mbbl/d of light crude oil
and NGLs being approximately 25,000 boe/d. The acquisition included over
510,000 net acres of undeveloped land. The vast majority of the acquired
properties is located in the Company's core regions and extends its Northern
Plains core region into the light crude 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
10
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 ("Horizon Project"). The Horizon Project is
designed as a phased development and includes the mining of bitumen combined
with an onsite upgrader. Phase 1 production is planned to begin in the second
half of 2008 at 110 mbbl/d of 34(degree) API light, sweet synthetic crude oil
("SCO"). Phase 2 would increase production to 155 mbbl/d of SCO in 2010. Phase
3 would further increase production to 232 mbbl/d of SCO in 2012. The phased
approach provides the Company with improved cost and project controls
including labour and materials management, and directionally mitigates the
effects of growth on local infrastructure.
Based upon stratigraphic drilling the Company's oil sands leases located near
Fort McMurray, Alberta contain an estimated 6 billion barrels of potentially
recoverable bitumen using existing mining and upgrading technologies.
Additional in-situ potential also exists on the western portions of the
leases. The first three phases of the Horizon Project, which encompasses only
a portion of these oil sands leases, will deliver approximately 37 years of
production without the declines normally associated with petroleum operations.
GLJ Petroleum Consultants ("GLJ"), a qualified independent third party
petroleum consultant firm, was retained by the Reserves Committee of Canadian
Natural's Board of Directors to evaluate the mining reserves associated with
the Horizon Project. Their report estimated that 3.4 billion barrels of gross
proved and probable bitumen reserves are located on the leases associated with
the first three phases of the Horizon Project.
In August 2005, the Company entered into an agreement to obtain pipeline
transportation service for the Horizon Project. This agreement allows Canadian
Natural to gain access to major sales pipelines out of Edmonton for the
Company's synthetic crude oil which will be produced at the Horizon Project,
while at the same time provides significant quality benefits associated with
being the only shipper on the Horizon Pipeline. The expected twinning of the
existing Alberta Oil Sands Pipeline ("AOSPL"), resulting in two parallel
pipelines, one of which will be dedicated to Canadian Natural, combined with a
new pipeline constructed from the Horizon Project site down to the AOSPL
Terminal (collectively, the "Horizon Pipeline"), will provide crude oil
transportation service for the Horizon Project. The initial term of the
agreement is 25 years, which will commence on the in-service date. In addition
to having the option to renew the agreement for successive 10-year terms,
Canadian Natural has the right to request incremental expansions of the
Horizon Pipeline based upon applicable National Energy Board approved
multi-pipeline economics. The construction of the Horizon Pipeline is expected
to begin in 2006 and will be fully operational by mid 2008 to coincide with
first production at the Horizon Project. See below "Horizon Oil Sands
Project".
In April 2005, the Company monetized, through a sale, a large portion of its
overriding royalty interests on various producing properties throughout
Western Canada and Ontario for proceeds of approximately $345 million. In 2004
these interests produced approximately 3,700 boe/d and over the 2003 and 2004
fiscal years cash flow from these interests averaged approximately $50 million
per year. As part of the transaction, the Company purchased 3,858,520 trust
units of Freehold Royalty trust for $60 million and, after the mandatory hold
period, the trust units were sold to an underwriting group pursuant to an
agreement for a net gain of approximately $11 million.
11
On June 1, 2005, the Company issued $400 million of 10-year 4.95 per cent
unsecured notes maturing June 1, 2015 pursuant to a short form shelf
prospectus for the issuance of medium term notes in Canada dated August 1,
2003. In January 2006 the Company issued a further $400 million of 4.50 per
cent unsecured notes maturing January 23, 2013 as the first issuance under the
short form Canadian base shelf prospectus dated August 29, 2005, which allows
for the issuance of debt securities in an aggregate principal amount of up to
C$2 billion.
During 2005, the Company completed 96 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties at an
aggregate net expenditure of $134 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 a large portion of its overriding royalty interests and
operated and non-operated properties not located in the Company's core regions
for proceeds of $454 million.
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 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 approval of a
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 NGLs from each province.
Government royalties are payable on crude oil and natural gas production from
12
leases owned by the province. The 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.
In addition to government royalties, the Company is subject to federal and
provincial income taxes in Canada at a combined rate of approximately 38.1 per
cent after allowable deductions.
UNITED KINGDOM
Under existing law, the UK Government has broad authority to regulate the
petroleum industry, including 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. Approvals granted on or after March 16,
1993 are exempted from PRT and government royalties. 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 deductible for CT purposes. The CT rate,
which became effective April 1, 1999, was set at 30 per cent. In its 2002
budget speech by the UK Chancellor of the Exchequer, the UK Government
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. In December 2005, the UK
Chancellor of the Exchequer announced an increase to the Supplementary CT from
10 per cent to 20 per cent, effective January 1, 2006.
OFFSHORE WEST AFRICA
Terms of licences, including royalties and taxes payable on production or
profit sharing arrangements, vary by country and, in some cases, by concession
within each country. Development of the Espoir field on CI-26 and the Baobab
Field on CI-40, in 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").
In October 2005, Canadian Natural completed the acquisition of the permit to
develop the Olowi Field, offshore Gabon. Development of this field 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.
RISK FACTORS
VOLATILITY OF CRUDE OIL AND NATURAL GAS PRICES
The Company's financial condition is 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 the
Company's 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.
Crude 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
13
and Asian economies, government regulation, political stability in the Middle
East and elsewhere, the foreign supply of crude oil, the price of foreign
imports, the availability of alternate fuel sources and weather conditions.
Natural gas prices realized by the Company are 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 GAAP. If crude oil and natural gas prices
decline, the carrying value of the assets could be subject to downward
revisions, and net earnings could be adversely affected.
Approximately 27 percent of the Company's 2005 production on a boe basis was
primary and thermal heavy crude oil. The market prices for heavy crude oil
differ from the established market indices for light and medium grades of
crude oil, due principally to the higher transportation and refining costs
associated with heavy crude oil. As a result, the price received for heavy
crude oil is generally lower than the price for medium and light crude oil,
and the production costs associated with heavy crude oil may be higher than
for lighter grades. Future differentials are uncertain and any increase in the
heavy crude oil differentials could have a material adverse effect on the
Company's business.
ENVIRONMENTAL RISKS
All phases of the crude 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.
14
NEED TO REPLACE RESERVES
Canadian Natural's future crude 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 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 crude 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 crude 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 crude oil and natural gas interests and the
transportation and marketing of crude oil, natural gas, NGLs 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 relate to operational risks, the cost of capital
available to fund exploration and development programs, fluctuation in foreign
exchange rates, the availability of skilled labour and manpower, 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.
15
Canadian Natural's private ownership of crude oil and natural gas properties
in Canada differs distinctly from its ownership interests in foreign crude 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 crude 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 crude oil, NGL and natural gas reserves
and the future net cash flow there from 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 crude oil, NGL 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 there
from, 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.
16
ENVIRONMENTAL MATTERS
The Company carries out its activities in compliance with all relevant
regional, national and international regulations and industry standards.
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 by changes in applicable legislation. 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 its 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 ("GHG") reduction; and flaring and venting
reduction. Canadian Natural participates in both the Canadian federal and
provincial regulated GHG emissions reporting for facilities with GHG emissions
greater than 100 thousand tonnes of CO2 equivalent per year. The Company
continues to quantify annual GHG emissions for internal reporting purposes.
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 to help us achieve our
overall goal of a net reduction of GHG emissions per unit of production.
The costs incurred by the Company for compliance with environmental matters
and site restoration amounted 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, 2005, 2004 and 2003.
DESCRIPTION OF THE BUSINESS
Canadian Natural is a Canadian based senior independent energy company engaged
in the acquisition, exploration, development, production, marketing and sale
of crude oil, NGLs, natural gas and bitumen production. 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 Canadian Natural 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 presence in
existing core regions.
17
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 43 per cent of 2005 production.
Virtually all of the Company's natural gas and NGLs production is located in
the Canadian provinces of Alberta and British Columbia and is marketed in
Canada and the United States. Light crude oil and NGLs, representing 26 per
cent of 2005 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 crude
oil operations in the Provinces of Alberta and Saskatchewan account for 27 per
cent of 2005 production. Other heavy crude oil, which accounts for 4 per cent
of 2005 production, is produced from the Pelican Lake area in north Alberta.
This production, which has medium crude oil netback characteristics, is
developed through a staged horizontal drilling program complimented by water
flooding. 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. Canadian Natural
expects its ownership of crude oil sands leases near Fort McMurray, Alberta to
provide a basis for long-term synthetic crude oil production growth. The first
three phases of the Horizon Project, which encompasses only a portion of these
oil sands leases is expected to deliver approximately 37 years of synthetic
crude oil production.
As a result of the Company's core undeveloped land base of 10.9 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.
18
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES
Set forth below is a summary of the principal crude oil, natural gas and oil
sands properties as at December 31, 2005. The information reflects the working
interests owned by the Company.
YEAR ENDED
2005 AVERAGE DAILY DECEMBER 31, MAJOR INFRASTRUCTURE
PRODUCTION RATES 2005 AS AT DECEMBER 31, 2005
--------------------- ----------------- ----------------------------
CRUDE BATTERIES/
OIL & NATURAL UNDEVELOPED COMPRESSORS & PLANTS/
NGLs GAS ACREAGE PLATFORMS
REGION mbbl mmcf (thousands) /FPSO
NORTH AMERICA
Northeast B. C. 6.7 434.4 2,027 1/9/-/-
Northwest Alberta 13.5 403.4 1,507 -/8/-/-
Northern Plains 181.8 419.2 6,594 12/6/-/-
Southern Plains 10.7 155.4 621 -/2/-/-
Southeast Saskatchewan 8.8 3.1 82 -/-/-/-
Non - core regions 0.2 0.8 236 -/-/-/-
Horizon Oil Sands - - 115 -/-/-/-
INTERNATIONAL
North Sea UK Sector 68.6 18.4 352 -/-/6/1
Offshore West Africa
Cote d'Ivoire 22.9 4.1 274 -/-/0/2
Gabon - - 152 -/-/-/-
Non - core regions
South Africa - 4,002 -/-/-/-
-------------------------------------------------------------------------------------------------------
TOTAL 313.2 1438.8 15,963 13/25/6/3
-------------------------------------------------------------------------------------------------------
19
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, 2005 by geographic region:
2005
-------------------------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
-------------------------------------------------------------------------------------------------------------------------
CANADA
32.1 7.2 39.3 179.9 21.1 201.0
Northeast B. C.
29.9 9.0 38.9 135.2 7.3 142.5
Northwest Alberta
63.5 11.5 75.0 671.4 51.9 723.3
Northern Plains
50.6 5.0 55.6 294.9 2.0 296.9
Southern Plains
1.0 - 1.0 43.0 - 43.0
Southeast Saskatchewan
- - - 0.3 - 0.3
Non - core regions
NORTH SEA UK SECTOR - 0.8 0.8 11.5 0.9 12.4
OFFSHORE WEST AFRICA
Cote d'Ivoire - 0.6 0.6 3.5 - 3.5
-------------------------------------------------------------------------------------------------------------------------
TOTAL 177.1 34.1 211.2 1339.7 83.2 1422.9
-------------------------------------------------------------------------------------------------------------------------
2004
-------------------------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
-------------------------------------------------------------------------------------------------------------------------
CANADA
23.8 6.2 30.0 146.8 14.4 161.2
Northeast B. C.
42.8 7.6 50.4 100.4 3.9 104.3
Northwest Alberta
116.6 26.6 143.2 333.8 23.2 357.0
Northern Plains
18.5 7.0 25.5 209.9 4.0 213.9
Southern Plains
- - - 12.5 - 12.5
Southeast Saskatchewan
- - - 0.5 0.3 0.8
Non - core regions
NORTH SEA UK SECTOR - 2.0 2.0 9.2 - 9.2
OFFSHORE WEST AFRICA
Cote d'Ivoire - 0.7 0.7 2.3 - 2.3
-------------------------------------------------------------------------------------------------------------------------
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
15.5 13.3 28.8 67.8 9.1 76.9
Northeast B. C.
31.7 11.8 43.5 69.9 7.9 77.8
Northwest Alberta
57.5 26.6 84.1 531.6 37.9 569.5
Northern Plains
33.0 4.0 37.0 387.9 5.0 392.9
Southern Plains
- - - 26.9 - 26.9
Southeast Saskatchewan
- - - 0.4 - 0.4
Non - core regions
NORTH SEA UK SECTOR - 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
-------------------------------------------------------------------------------------------------------------------------
20
PRODUCING CRUDE 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, 2005:
-----------------------------------------------------------------------------------------------------------------------
NATURAL GAS WELLS CRUDE OIL WELLS TOTAL WELLS
GROSS NET GROSS NET GROSS NET
-----------------------------------------------------------------------------------------------------------------------
CANADA
Northeast B. C. 1,177 983.7 278 204.4 1,455 1,188.1
Northwest Alberta 1,196 948.7 195 140.1 1,391 1,088.8
Northern Plains 3,502 2,923.7 5,799 5,291.9 9,301 8,215.6
Southern Plains 4,260 3,698.5 1,026 922.0 5,286 4,620.5
Southeast Saskatchewan - - 1,092 768.0 1,092 768.0
Non - core regions 837 334.3 1,483 470.0 2,320 804.3
UNITED STATES 4 0.5 2 0.2 6 0.7
NORTH SEA UK SECTOR 4 0.3 118 98.4 122 98.7
OFFSHORE WEST AFRICA
Cote d'Ivoire - - 15 8.7 15 8.7
-----------------------------------------------------------------------------------------------------------------------
TOTAL 10,980 8,889.7 10,008 7,903.7 20,988 16,793.4
-----------------------------------------------------------------------------------------------------------------------
All reserves data in the following property report is based on the applicable
independent engineering report. See below "Conventional Crude Oil, NGL and
Natural Gas Reserves" and "Oil Sands Mining Disclosure".
NORTHEAST BRITISH COLUMBIA
[GRAPHIC OMITTED]
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,
NGLs and natural gas. The Company holds working interests ranging up to 100
per cent and averaging 77 per cent in 3,776,051 gross (2,895,451 net) acres of
producing and undeveloped land in the region.
21
Crude oil reserves are found primarily in the Halfway or lower Halfway
formation, while natural gas and associated NGLs 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 434.4 mmcf/d in 2005 compared to the average of 437.3
mmcf/d in 2004. Crude oil and NGLs production was steady at to 6.7 thousand
bbl/d in 2005 from an average of 6.8 thousand bbl/d in 2004.
During 2005, 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 generally 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 2005, the Company drilled 10.9 (2004- 3.6) net crude oil wells, 201.1
(2004 - 167.0) net natural gas wells, 1.0 (2004 - 1.0) net
stratigraphic/service wells and 28.3 (2004 - 20.6) net dry wells on its lands
in this region for a total of 241.3 (2004 - 192.2) net wells. The Company held
an average 85.6 per cent working interest in these wells.
NORTHWEST ALBERTA
[GRAPHIC OMITTED]
The Company holds working interests ranging up to 100 per cent and averaging
76 per cent in 2,809,179 gross (2,128,874 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 meters. The northern portion of this core
22
region provides extensive multi-zone Cretaceous opportunities similar to the
geology of the Company's Northern Plains 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 403.4 mmcf/d in 2005 compared
to an average of 303.2 mmcf/d in 2004. Crude oil and NGLs production was
steady at 13.5 thousand bbl/d in 2005 from 10.9 thousand bbl/d in 2004.
During 2005, the Company drilled 12.9 (2004-5.8) net crude oil wells, 152.4
(2004-137.5) net natural gas wells, 0.7 (2004 - 1.5) net stratigraphic/service
wells, and 16.3 (2004-11.5) net dry wells on its lands in this region for a
total of 182.3 (2004-156.3) net wells. The Company held an average 82.1 per
cent working interest in these wells.
NORTHERN PLAINS
[GRAPHIC OMITTED]
The Company holds working interests ranging up to 100 per cent and averaging
84 per cent in 11,608,488 gross (9,806,002 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, NGLs and light crude oil are also
encountered at slightly greater 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 419.2 mmcf/d in 2005 compared to 429.9 mmcf/d in
2004. Crude oil and NGLs production from this region increased to 181.8
thousand bbl/d in 2005 from 166.3 thousand bbl/d in 2004. Production of
natural gas was negatively impacted by the shut-in effective July 1, 2004 of
approximately 11 mmcf/d in the Athabasca Wabiskaw-McMurray oil sands area
pursuant to the decision of the Alberta Energy and Utilities Board.
In February 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.
23
Natural gas in this region is produced from shallow, low-risk, multi-zone
prospects and more recently from the Horseshoe Canyon coal bed methane
("CBM"). The Company targets low-risk exploration and development
opportunities and plans to expand its commercial CBM project. During 2005, CBM
development drilling included 42 net wells and the Company has an inventory of
over 500 net Horseshoe Canyon CBM locations.
In the area near Lloydminster, Alberta, reserves of heavy crude oil (averaging
12(Degree)-14(degree) 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 crude 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 crude 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 crude 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 contiguous to the Company's holdings. With
the operations combined in 2000, development 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 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 bbl/d of hot, unblended crude oil to sales facilities
at Hardisty, Alberta and in 2003 its capacity was expanded to handle up to 72
thousand bbl/d. 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.
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. The ECHO Pipeline system permits the Company to transport
approximately 80 per cent of its heavy crude oil to the international mainline
liquids pipelines.
Production from the 100% owned Primrose and Wolf Lake Fields located near
Bonnyville, Alberta involves processes that utilize steam to increase the
recovery of the crude 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 thereby improving its flow characteristics. There is
also an infrastructure of gathering systems, a processing plant with a
capacity of 80 thousand bbl/d of crude oil 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 apply
24
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 was
effectively completed in 2005 with total capital expenditures of approximately
$300 million incurred. The Primrose North expansion entails a remote steam
treating facility and additional high pressure wells. First crude oil
production from the expansion project began in January 2006. Also in 2004 the
Company filed a public disclosure document for regulatory approval of its
Primrose East project, a new facility located about 15 kilometers from its
existing Primrose South steam plant and 25 kilometers from its Wolf Lake
central processing facility. The development application was submitted to the
Alberta Energy and Utilities Board in January 2006, with potential impacts
associated with the use of bitumen as fuel being evaluated in the
Environmental Impact Assessment. The Company expects construction to begin in
2007, with the first steam scheduled for January 2009. A 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 holdings at Pelican Lake; generally having a 100
per cent ownership rate by the Company. These lands contain reserves of
12(Degree)-17(Degree) API heavy crude oil. Operating costs are low due to the
absence of sand production and 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 ("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 was slow. Due to the slow response
time, the Company reverted to a waterflood scheme for this field. The
waterflood provided initial production increases as expected and has shown
positive waterflood response. To enhance the waterflood scheme, in the second
quarter of 2005, the Company installed facilities for a polymer flood pilot
test. Initial behaviour of the polymer flood pilot test has been positive,
however definitive conclusions regarding the feasibility of the program will
not be known until late 2006 or early 2007. In advance of the pilot test
results, preparations for commercial polymer flood have commenced including
source water development and advance ordering of some of the long lead time
equipment.
During 2005, the Company drilled 536.1 (2004 - 287.0) net crude oil wells,
198.9 (2004 - 163.4) net natural gas wells, 108.9 (2004 - 112.0) net
stratigraphic/service wells, and 63.4 (2004 - 49.8) net dry wells for a total
of 907.3 (2004 - 612.2) net wells. The Company's average working interest in
these wells was 91.7 per cent.
25
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN
[GRAPHIC OMITTED]
In the Southern Plains area, the Company holds interests ranging up to 100 per
cent and averaging 83 per cent in 2,037,923 gross (1,699,254 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
higher than average 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 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 10.7
thousand bbl/d of crude oil and NGLs compared to 12.7 thousand bbl/d in 2005.
Natural gas production amounted to 155.4 mmcf/d in 2005 compared to the 155.5
mmcf/d averaged in 2004.
During 2005, the Company drilled a total of 9.0 (2004 - 7.8) net crude oil
wells, 336.5 (2004 - 220.6) net natural gas wells, 1.7 (2004 - 1.0) net
stratigraphic/service well and 7.0 (2004 - 11.0) net dry wells in this region
for a total of 354.2 (2004 - 240.4) net wells. The Company's average working
interest in these wells was 81.0 per cent.
The Williston Basin is located in Southeast 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.
26
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 8.8 thousand bbl/d of
crude oil and NGLs in 2005 compared to 9.3 thousand bbl/d in 2004. Natural gas
production was steady averaging 3.1 mmcf/d in both 2005 and 2004.
The Company drilled 43.0 (2004 - 12.5) net crude oil wells, 1.0 (2004 - 0.0)
net gas well, 7.6 (2004 - 0.0) net stratigraphic/service wells and 0.0 (2004 -
0.0) net dry wells in this region in 2005, for a total of 51.6 (2004 - 12.5)
net wells. The Company's average working interest in these wells is 83.2 per
cent.
HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
Canadian Natural owns a 100 per cent working interest in its Athabasca Oil
Sands leases in Northern Alberta, of which a portion (being lease 18) is
subject to a 5 per cent net carried interest in the bitumen development. The
Horizon Oil Sands Project ("Horizon Project") is located on these leases,
about 70 kilometers north of Fort McMurray. The project includes surface oil
sands mining, bitumen extraction, bitumen upgrading to produce a 34 o -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 2011 or 2012. Phase 1 production is targeted to begin in
the second half of 2008 at 110 thousand bbl/d of SCO. Current plans have Phase
2 increasing production to 155 thousand bbl/d of SCO in 2010 and Phase 3
further increasing production to 232 thousand bbl/d of SCO in 2012. These
targeted rates of production represent nominal design capacity. The Company is
currently evaluating the opportunity to combine Phase 2 and Phase 3 for a
joint operational date of 2011. 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 may mitigate
any negative effects of growth on local infrastructure.
Using a cost environment associated with a US $45 WTI price per barrel of
crude oil, total estimated capital construction costs of the phased
development are $10.8 billion, of which approximately $6.8 billion, including
27
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 $15 per barrel (based upon a
natural gas price input of US$ 5.83/mcf).
Canadian Natural filed an application for regulatory approval of the Horizon
Project in June 2002. The application included a comprehensive environmental
impact assessment and 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 developed in the context of 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.
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 for Phase 1,
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 Project. The third phase of FEL for
Phase 2 is expected to be completed in the first quarter of 2007.
The Horizon Project 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 2005, Canadian
Natural's Horizon Project team, consisted of 521 permanent employees. This
represents a total of 67 per cent of the 773 staff positions required by year
end 2006. Of the 252 outstanding positions, 110 are filled by contractors on
an interim basis for total of 82 per cent of our 2006 year end position
requirements.
Horizon Project costs were approximately $1.5 billion in 2005 and cumulative
expenditures were approximately $2.2 billion through the end of 2005. These
expenditures include capitalized interest, stock based compensation, lease
28
evaluation, engineering definition, technology acquisition, completion of road
infrastructure to the site, initial camp construction, detailed engineering,
significant site development and initial foundation construction. Construction
costs for 2006 are budgeted to be approximately $2.6 billion reflecting major
expenditures for detailed engineering, procurement and construction of Phase 1
of the Project. In addition, capital expenditures of $128 million are budgeted
for Phase 2 EDS development in 2006.
During 2005, the Company drilled 126 (2004 - 218) stratigraphic test wells to
further delineate the ore body and confirm resource quality and quantity.
UNITED KINGDOM NORTH SEA
[GRAPHIC OMITTED] [GRAPHIC OMITTED]
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 595,051 gross (444,314 net) acres of producing and
non-producing properties in the UK sector of the North Sea. In 2005, the
Company produced from 16 crude oil fields.
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 its 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. The
Company also owns a 45.7 per cent operated working interest in the Kyle Field.
Beginning in the third quarter of 2005, all production for the Kyle Field was
processed through the Banff FPSO facilities. The consolidation of these
production facilities is expected to result in lower combined operating costs
from these fields.
29
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.
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 by the existing processing facilities.
During 2005, production to the Company from this region averaged 68.6 thousand
bbl/d of crude oil, up from 64.7 thousand bbl/d in 2004. Natural gas
production averaged 18.4 mmcf/d in 2005, down from 50.4 mmcf/d in 2004
primarily due to the re-injection of associated natural gas production into
the Banff Field for improved crude oil recovery.
The Company drilled 11.5 (2004 - 9.2) net crude oil wells, 0.9 (2004 - 2.7)
net stratigraphic/service wells and 1.7 (2004 - 2.0) net dry wells in 2004 in
this region for a total of 14.1 (2004 - 13.9) net wells. The Company's average
working interest in these wells is 88.0 per cent.
OFFSHORE WEST AFRICA
[GRAPHIC OMITTED]
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 1,596,013 gross (887,657 net) acres in
those countries. Since 2000, the Company has either relinquished or sold all
of its interests in offshore Angola.
In 2005, the Company acquired the permit to develop the Olowi Field, offshore
Gabon, West Africa, consisting of 151,818 acres. The Company has a 90 per cent
interest in a production sharing agreement for the block.
The Company also has a 100 per cent interest in 4,001,574 acres offshore South
Africa where it is shooting and evaluating seismic data and undertaking
environmental studies.
30
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 58.7 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. The
construction and installation of a new wellhead tower for the West Espoir part
of the field were completed in 2005. An infill drilling program in East Espoir
was commenced in 2005 and following its completion development drilling will
commence at West Espoir.
Crude oil from the East Espoir Field 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.
The unsuccessful Zaizou exploration well was drilled in block CI-40 in 2005.
In the first quarter of 2001, the Company drilled and tested the Baobab
exploration prospect, identified on Block CI-40, eight kilometers south of the
Espoir facilities, in which the Company has a 58 per cent interest. 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 first oil was achieved in August 2005 producing at approximately 30
thousand bbl/d net to Canadian Natural from 4 wells. Upon completion of
drilling additional wells in 2006, production levels are expected to increase
another 5 thousand bbl/d net to the Company. In East Espoir, two of four
infill wells were completed in 2005 increasing production by 3 thousand bbl/d
in the second quarter of 2005. The remaining two infill wells are expected to
be completed in 2006. Construction of the West Espoir drilling tower was
completed and installed to facilitate development drilling of the reservoir
and it is expected that production will commence in 2006.
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 a nearby country if the situation warrants such a
move.
During 2005, Company production averaged 22.9 thousand bbl/d of crude oil
compared to 11.6 thousand bbl/d in 2004. Company natural gas production
amounted to 4.2 mmcf/d in 2005 compared to 7.5 mmcf/d in 2004.
In 2005, the Company drilled 3.5 (2004 - 2.3) net crude oil wells, 1.1 (2004 -
0.0) net stratigraphic/service wells and 0.6 (2004 - 0.7) net dry wells for a
total of 5.2 (2004 - 3.0) net wells. The Company's average working interest in
these wells is 58.2 per cent.
31
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 data 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 data and the well results during 2004
and even though additional review of seismic and geological data on Block 16
indicates that significant upside remains a possibility, the risk level
associated with Block 16 is outside the normal operating parameters of the
Company. As a result, the Company entered into an agreement to dispose of its
interest in Block 16 effective December 31, 2005. As of the sale of Block 16,
the Company no longer has any holdings in Angola.
GABON
[GRAPHIC OMITTED]
The Company acquired permit (No. G4-187) comprising a 90 per cent operating
interest in the production sharing agreement for the block containing the
Olowi Field, located about 20 kilometers from the Gabonese coast and in 30
meters water depth. Olowi has been delineated by the drilling of 15 wells on
the block and is estimated to potentially contain up to 500 million barrels of
34(0) API light crude original oil in place. The crude oil reservoir is
overlain by a large gas cap with potentially up to 1 trillion cubic feet of
original gas in place. A development plan, comprising an FPSO and four
drilling towers, was filed with the Gabonese Government in late 2005 and
approved in February 2006. The development of the crude oil reserves will
commence in late 2006 with first production targeted for late 2008 at a rate
of 20 thousand bbl/d.
32
B. CONVENTIONAL CRUDE OIL, NGL, AND NATURAL GAS RESERVES
For the year ended December 31, 2005, Canadian Natural retained qualified
independent reserve evaluators, Sproule Associates Limited ("Sproule") and
Ryder Scott Company ("Ryder Scott"), to evaluate 100% of the Company's
conventional proved and probable crude oil, NGL and natural gas reserves and
prepare Evaluation Reports on these reserves. Sproule evaluated the Company's
North America conventional assets and Ryder Scott evaluated its international
conventional assets. The Company has been granted an exemption from the
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. There are two principal differences
between the two standards. The first is the additional requirement under NI
51-101 to disclose both proved, proved and probable reserves, as well as the
related net present value of future net revenues using forecast prices and
costs. The second is in the definition of proved reserves; however, as
discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the
standards that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.
The Company has disclosed proved conventional reserves and the Standardized
Measure of discounted future net cash flows using constant prices and costs as
mandated by the SEC in the supplemental oil and gas information section of its
annual report. The Company has also elected to provide the net present value
of these same conventional proved reserves as well as the conventional proved
and probable reserves and the net present value of these reserves under the
same parameters as additional voluntary information. In addition to the
constant price and cost scenario, the Company has also elected to provide both
conventional proved and conventional proved and probable reserves, as well as
the net present value of these reserves, using forecast prices and costs as
voluntary additional information.
Reserves and net present values of these reserves 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.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule and
Ryder Scott to review the qualifications of and procedures used by each
evaluator in determining the estimate of the Company's quantities and net
present value of remaining conventional crude oil, NGL and natural gas
reserves.
The following tables summarize the evaluations of conventional reserves and
estimated net present values of these reserves at December 31, 2005.
THE ESTIMATED NET PRESENT VALUES OF RESERVES 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. ONLY FUTURE DEVELOPMENT COSTS AND
ASSOCIATED FUTURE MATERIAL WELL ABANDONMENT LIABILITIES HAVE BEEN APPLIED WITH
THE EXCEPTION OF OFFSHORE WEST AFRICA WHERE ALL EXISTING AND FUTURE
ABANDONMENT LIABILITIES HAVE BEEN INCLUDED. NO INDIRECT COSTS SUCH AS
OVERHEAD, INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED FROM THE
33
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.
NET CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES (NET OF ROYALTIES)
Constant Prices and Costs
----------------------------------------------------------------------------
Crude Oil & NGLs (mmbbl) Natural Gas (bcf)
Total Total Total Total
Proved Proved and Probable Proved Proved and Probable
Reserves Reserves Reserves Reserves
------------------------------------- -----------------------------------
NORTH AMERICA
Canada 694 1,035 2,739 3,546
United States - - 2 2
INTERNATIONAL
United Kingdom 290 417 29 69
Cote d'Ivoire 119 189 72 110
Gabon 15 17 - -
------------------------------------- -----------------------------------
TOTAL 1,118 1,658 2,842 3,727
===================================== ===================================
CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES
Constant Prices and Costs
---------------------------------------------------------------------------
Crude Oil & NGLs (mmbbl) Natural Gas (Bcf)
Company Gross Net Company Gross Net
------------------------------------- -----------------------------------
Proved developed reserves 762 696 2,871 2,326
Proved undeveloped reserves 461 422 619 516
------------------------------------- -----------------------------------
TOTAL PROVED RESERVES 1,223 1,118 3,490 2,842
TOTAL PROVED AND PROBABLE
RESERVES 1,801 1,658 4,568 3,727
===================================== ===================================
ESTIMATED NET PRESENT VALUES
($ millions) Constant Prices and Costs
--------------------------------------------------------------------------
Undiscounted Discounted at
10% 15% 20%
-------------------- -----------------------------------------------
Proved developed reserves 37,183 24,275 20,939 18,514
Proved undeveloped reserves 12,035 6,342 4,881 3,843
-------------------- ---------------- ----------- -----------
TOTAL PROVED RESERVES 49,218 30,617 25,820 22,357
TOTAL PROVED AND PROBABLE RESERVES 68,543 38,682 31,642 26,764
==================== ================ =========== ===========
34
CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES
Forecast Prices and Costs
---------------------------------------------------------------------------
Crude Oil & NGLs (mmbbl) Natural Gas (bcf)
Company Gross Net Company Gross Net
------------------------------------- -----------------------------------
Proved developed reserves 752 685 2,814 2,276
Proved undeveloped reserves 462 421 617 517
TOTAL PROVED RESERVES 1,214 1,106 3,431 2,793
TOTAL PROVED AND PROBABLE RESERVES 1,792 1,642 4,485 3,657
ESTIMATED NET PRESENT VALUES
($ millions) Forecast Prices and Costs
---------------------------------------------------------------------------
Undiscounted Discounted at
10% 15% 20%
-------------------- -----------------------------------------------
Proved developed reserves 31,154 22,175 19,662 17,774
Proved undeveloped reserves 10,543 5,501 4,232 3,338
TOTAL PROVED RESERVES 41,697 27,676 23,894 21,112
TOTAL PROVED AND PROBABLE RESERVES 57,892 34,446 28,800 24,849
==================== ===============================================
NOTES
1. "Company Gross" reserves means the total working interest share of
remaining recoverable reserves owned by the Company before consideration
of royalties.
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 net present values using forecast prices and costs as well as
before royalties as additional voluntary information.
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 net present 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 NGLs, 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 net present 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 net present 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.
35
9. The constant price and cost case assumes that prices in effect at
year-end 2005 adjusted for quality and transportation as well as the
2005 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 been
held constant at the 2006 values shown below. 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 Edmonton North
Average Henry Hub Huntingdon/ Average WTI@ Heavy 12 Par Sea
Price Louisiana AECO Sumas Price Cushing(i) (degree)API (ii) Brent
YEAR C$/MCF US$/MMBTU C$/MMBTU C$/MMBTU C$/BBL US$/BBL C$/BBL C$/BBL US$/BBL
---- ------ --------- -------- -------- ------ ------- ------ ------ -------
2006 9.45 10.08 9.99 9.53 46.12 61.04 32.64 68.12 58.21
(i) "WTI @ Cushing" refers to the price of West Texas
Intermediate crude oil at Cushing, Oklahoma.
(ii) "Edmonton Par" refers to the price of light gravity
(40o API), low sulphur content crude oil at Edmonton,
Alberta.
(iii) Foreign exchange rate used was US$0.8598/C$1.00
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, NGLs and natural gas price forecasts were based on Sproule's
December 31, 2005 crude oil, NGLs and natural gas pricing model. The
Company's weighted average crude oil and NGLs price and the weighted
average natural gas price in 2005 were $46.86 per barrel and $8.57 per
mcf respectively, before adjustments due to hedging. The crude oil and
natural gas forecast prices used in the Evaluation Reports are as
follows:
NATURAL GAS CRUDE OIL & NGLs
------------------------------------------------ ---------------------------------------------------------
Company Company Hardisty Edmonton North
Average Henry Hub Huntingdon/ Average WTI@ Heavy 12 Par Sea
Price Louisiana AECO Sumas Price Cushing(i) (degree)API (ii) Brent
YEAR C$/MCF US$/MMBTU C$/MMBTU C$/MMBTU C$/BBL US$/BBL C$/BBL C$/BBL US$/BBL
---- ------ --------- -------- -------- ------ ------- ------ ------ -------
2006 11.07 11.59 11.58 11.34 48.30 60.81 37.07 70.07 58.81
2007 10.33 10.11 10.84 10.70 49.59 61.61 37.29 70.99 59.58
2008 8.43 8.50 8.95 8.81 45.31 54.60 34.23 62.73 52.54
2009 7.35 7.58 7.87 7.73 42.12 50.19 32.27 57.53 48.10
2010 7.05 7.32 7.57 7.43 39.53 47.76 31.15 54.65 45.64
2011 7.21 7.43 7.70 7.56 40.57 48.48 31.94 55.47 46.32
2012 7.34 7.54 7.83 7.69 40.14 49.20 32.74 56.31 47.02
2013 7.48 7.66 7.96 7.82 41.22 49.94 33.56 57.16 47.72
2014 7.61 7.77 8.09 7.95 41.34 50.69 34.39 58.02 48.44
2015 7.75 7.89 8.23 8.09 42.02 51.45 35.23 58.89 49.17
2016 7.86 8.01 8.37 8.23 42.03 52.22 36.08 59.78 49.90
(i) Foreign exchange rate used was US$0.8598/C$1.00
throughout the forecast
11. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and NGLs, less all
capital costs, production taxes, and operating costs and before
provision for income taxes, administrative overhead costs and existing
asset abandonment liabilities with the exception of Offshore West Africa
where existing asset liabilities were included.
36
12. The estimated total development capital costs net to the Company
necessary to achieve the estimated future net "proved" and "proved and
probable" production revenues are:
PROVED PROVED AND PROBABLE
----------------------------------------------------------------------------------------------
FORECAST PRICE CASE CONSTANT PRICE CASE FORECAST PRICE CASE CONSTANT PRICE CASE
($ millions) ($ millions) ($ millions) ($ millions)
----------------------------------------------------------------------------------------------
2006 1,433 1,412 1,614 1,593
2007 815 774 1,140 1,087
2008 1,017 930 1,774 1,645
2009 428 373 1,144 1,023
2010 315 286 794 718
2011 173 154 306 273
2012 223 191 362 313
2013 180 102 200 168
2014 87 115 222 140
2015 143 120 247 249
2016 182 141 220 173
2017 174 136 238 188
Thereafter 555 398 773 554
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 found by Sproule and Ryder Scott to be
reasonable and no field inspection was conducted.
A report on conventional reserves data by Sproule and Ryder Scott and a report
on oil sands mining reserves data by GLJ are provided in Schedule A to this
Annual Information Form. A report by the Company's management and directors on
crude oil and natural gas disclosure is provided in Schedules B to this Annual
Information Form. The Company does not file estimates of its total crude oil
and natural gas reserves with any U. S. agency or federal authority other than
the SEC.
37
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL 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 & NGLs (mmbbl) 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 2,552
------------------------------------------------------------------------------------------------
Extensions & Discoveries 17 - - 17 334 - - 334
Infill Drilling 24 35 - 59 74 - - 74
Improved Recovery 1 10 - 11 6 - - 6
Property purchases 36 38 - 74 182 10 - 192
Property disposals - - - - (8) - - (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 2,591 27 72 2,690
------------------------------------------------------------------------------------------------
Extensions & Discoveries 98 - - 98 506 - - 506
Infill Drilling 3 3 2 8 22 - - 22
Improved Recovery - - - - 8 - - 8
Property purchases - - 15 15 6 - - 6
Property disposals (3) - - (3) (23) - - (23)
Production (70) (25) (8) (103) (411) (7) (1) (419)
Revisions of prior estimates 18 9 10 37 42 9 1 52
------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 694 290 134 1,118 2,741 29 72 2,842
------------------------------------------------------------------------------------------------
PROVED AND PROBABLE RESERVES
------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2003 857 317 133 1,307 2,919 102 72 3,093
------------------------------------------------------------------------------------------------
Extensions & Discoveries 20 - - 20 418 - - 418
Infill Drilling 29 49 - 78 106 - - 106
Improved Recovery 2 10 - 12 6 - - 6
Property purchases 49 49 - 98 236 18 - 254
Property disposals - - - - (10) - - (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 3,319 57 90 3,466
------------------------------------------------------------------------------------------------
Extensions & Discoveries 200 - - 200 645 - - 645
Infill Drilling 3 5 6 14 23 - 1 24
Improved Recovery - - - - 14 - - 14
Property purchases - - 17 17 8 - - 8
Property disposals (4) - - (4) (30) - - (30)
Production (70) (25) (8) (103) (411) (7) (1) (419)
Revisions of prior estimates (20) 22 (5) (3) (20) 19 20 19
------------------------------------------------------------------------------------------------
RESERVES, DECEMBER 31, 2005 1,035 417 206 1,658 3,548 69 110 3,727
------------------------------------------------------------------------------------------------
Information on the Company's conventional crude oil, NGLs and natural gas
reserves is provided in accordance with United States FAS 69, "Disclosures
About Oil and Gas Producing Activities" in the Company's 2005 Annual Report
under "Supplementary Oil and Gas Information" on pages 97 to 101 and is
incorporated herein by reference.
38
D. OIL SANDS MINING DISCLOSURE
INTRODUCTION
Canadian Natural holds a 100 per cent working interest in its Athabasca Oil
Sands leases in Northern Alberta, of which a portion (being lease 18), is
subject to a 5 per cent net carried interest in the bitumen development. The
Horizon Project was initiated in 2000 to evaluate the potential for mining and
processing the oil sands on these leases.
The Horizon Project is located in northeastern Alberta approximately 70
kilometers north of Fort McMurray in Townships 96 and 97, Ranges 11, 12 and
13, west of the 4th Meridian. The project site is accessible by a private road
as well as a private airstrip. Figure 1 shows the location of the Horizon
Project within Alberta, Canada and within the region. The leases being
developed for the Horizon Project are 18, 25, 10, 19 and 20. Canadian
Natural's development plan for the Horizon Project is to produce 232,000
barrels of synthetic crude oil per day. The project production schedule has
been developed such that production rates are increased over three phases.
Synthetic crude oil production is planned for the second half of 2008 at 110
thousand bbl/d, increasing to 232 thousand bbl/d by the third quarter of 2011.
Mining of the oil sands will be done using conventional truck and shovel
technology. The ore is then processed through extraction and froth treatment
to produce bitumen, which is upgraded on-site into synthetic crude oil. The
synthetic crude oil is transported from the site by pipeline to the Edmonton
area for distribution. An on-site cogeneration plant provides power and steam
for the operation. Preparation for construction of Phase 1 of the Horizon
Project began in late 2004. Total targeted capital costs for all three phases
of the development are projected to be approximately $10.8 billion at a cost
environment associated with a US $45 WTI price per barrel of crude oil.
An independent qualified reserves evaluator, GLJ Petroleum Consultants
("GLJ"), was retained to evaluate 100 per cent of the first three phases of
the Horizon Project's development plan. GLJ's Evaluation Report indicates that
the gross proved and probable reserves associated with the Horizon Project are
2.9 billion barrels of synthetic crude oil with a production life of 37 years.
Since 1999, Canadian Natural has acquired over 46,000 hectares, comprising 11
leases in the Fort McMurray area.
39
FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED] [GRAPHIC OMITTED]
TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES
===========================================================================================================
SHORT LEASE NAME OFFICIAL LEASE NUMBER LEASE EXPIRY DATE(1) AREA IN HECTARES
===========================================================================================================
Lease 18 727912T18 Continued Producing(2) 19,988
-----------------------------------------------------------------------------------------------------------
Lease 10 7400120010 December 14, 2015 3,840
-----------------------------------------------------------------------------------------------------------
Lease 25 7401050025 May 17, 2016 1,536
-----------------------------------------------------------------------------------------------------------
Lease 11 7400120011 December 14, 2015 518
-----------------------------------------------------------------------------------------------------------
Lease 12 7400120012 December 14, 2015 9,216
-----------------------------------------------------------------------------------------------------------
Lease 13 7400120013 December 14, 2015 69
-----------------------------------------------------------------------------------------------------------
Lease 15 7400120015 December 14, 2015 1,536
-----------------------------------------------------------------------------------------------------------
Lease 19 7402050019 May 30, 2017 5,120
-----------------------------------------------------------------------------------------------------------
Lease 20 7402050020 May 30, 2017 768
-----------------------------------------------------------------------------------------------------------
Lease 6 7597050T06 May 6, 2012 2,584
-----------------------------------------------------------------------------------------------------------
Lease 7 7597050T07 May 6, 2012 1,144
===========================================================================================================
(1) The Company can apply for an extension of the leases past the expiry
date.
(2) Pursuant to section 14 of the Oil Sands Tenure Regulation.
Lease 18, the main oil sand lease for the Horizon Project, has a gradual
topographic slope from west to east. To the west, the topography begins to
rise into the Birch Mountains and reaches an elevation of 485 meters above sea
level in the northwest corner of the lease. To the east, the elevation drops
sharply at the Athabasca River escarpment to 230 meters above sea level along
the river. The Tar and Calumet Rivers flow through the lease.
40
PROJECT DEVELOPMENT
On June 28, 2002, Pursuant to Sections 10 and 11 of the Oil Sands Conservation
Act, Canadian Natural filed Application No. 1273113 for approval for an oil
sands mine, a bitumen extraction plant, a bitumen upgrader and associated
facilities for the proposed Horizon Project. As part of the application to the
Energy and Utilities Board, the Company also submitted an Environmental Impact
Assessment ("EIA") report to the Director of the Regulatory Assurance
Division, Alberta Environment, pursuant to the Environmental Protection
Enhancement Act ("EPEA"). On June 26, 2003, the Federal Minister of Fisheries
and Oceans referred the EIA of the project to a review panel charged with
fulfilling the review as required by both the Canadian Environmental
Assessment Act ("CEAA") and the Energy Resources Conservation Act ("ERCA"). A
public hearing was held in Fort McMurray, Alberta on September 15-19, 22-26
and 29, 2003. The application and hearing provided significant background
detail on the geology, mine planning and development scheme and formed the
basis for the approval from the EUB in February 2004 and Alberta Environment
("AENV") under the Environmental Protection and Enhancement Act, in April
2004.
The following are the primary regulatory applications and approvals for the
Horizon Project, which contain information pertaining to the project of a
material engineering, geologic or metallurgic nature:
1. Application for Approval of Horizon Oil Sands Project submitted in
June 2002 to the EUB (Application No.1273113) and AENV (Application
No. 001-149968) (available at the EUB library, 640 5th Ave. SW,
Calgary, Alberta - Tel: (403) 297-8311).
2. Supplemental Information for the Horizon Oil Sands Project
(Application No. 1273113 and Application No. 001-149968) submitted
in March 2003 to the EUB and AENV) (available at the EUB library,
640 5th Ave. SW, Calgary, Alberta - Tel: (403) 297-8311).
3. Horizon Oil Sands Project Decision 2004-005 by a joint panel review
established by the EUB and the Government of Canada dated January
27, 2004 (available online at www.eub.gov.ab.ca).
4. Horizon Oil Sands Project Order in Council Authorization 26/2004 by
the Province of Alberta dated February 4, 2004 (available at the EUB
library, 640 5th Ave. SW, Calgary, Alberta - Tel: (403) 297-8311).
5. Horizon Oil Sands Project Approval No. 9752 by the EUB dated
February 10, 2004 (available at the EUB library, 640 5th Ave. SW,
Calgary, Alberta - Tel: (403) 297-8311).
6. Horizon Oil Sands Project Environmental Protection and Enhancement
Act Approval No. 149968-00-01 from AENV dated April 6, 2004
(available online at www.gov.ab.ca/env/water/approvalviewer.html
search parameter - Approval No. 149968-00-01).
7. Horizon Oil Sands Project Water Act Approval No. 00201931-00-00 from
AENV dated April 6, 2004 (available online at
www.gov.ab.ca/env/water/approvalviewer.html search parameter -
Approval No. 149968-00-01).
41
As of year-end 2005, key development achievements associated with the Horizon
Project were as follows:
o Phase 1 Construction is 19% complete.
o Mine overburden is at 6.7 million bank cubic meters of material
removed.
o Coker and Extraction Separation Cell foundations are complete.
o Critical path underground piping is complete.
The Coker Drums and Naphtha Reactor arrived on site in January 2006
REGIONAL AND PROJECT GEOLOGY
In the area of the Horizon Project, the oil sands resource is found within the
Cretaceous McMurray Formation. The McMurray Formation is comprised of a
sequence of uncemented quartz sands and associated shales that reside above
the unconformity with the underlying Upper Devonian carbonates (limestone) of
the Waterways Formation. The general stratigraphy of the Horizon Oil Sands
Project is shown in Figure 2.
The McMurray Formation was formed by the infilling of a broad northwest
trending depression in the exposed Devonian limestone landscape by mostly
non-marine and estuarine sediments about 115 million years ago. The deposition
of these terrestrial derived sediments ended when the Boreal Sea transgressed
the entire region, ushering in marine conditions that formed the Clearwater
Formation shales and glauconitic Wabiskaw member. This interplay between
rising sea level and sediment transport from the northeast gave rise to
various depositional environments (fluvial, estuarine, and marine). The entire
McMurray/Clearwater succession was (most recently about 10,000 years ago)
covered by unconsolidated sands, silts, and clays (glacial drift) deposited by
glaciers as they melted and receded from the region at the end of the last ice
age.
The McMurray Formation at the site of the Horizon Project is subdivided into
three informal members: lower, middle, and upper. These informal divisions
correspond to changes in the depositional environments within the McMurray
from predominantly fluvial to tidal/estuarine through to tidal/marine
conditions. Most of the Horizon Project's oil sands resource is found within
the lower and middle McMurray.
The lower McMurray, where present, is comprised of predominantly fluvial
channel deposits. The lower McMurray occupies lows on the Devonian (Paleozoic)
surface resulting in the thickest McMurray intervals. Clean sands in these
fluvial channels result in excellent quality ore. Flood plain deposits of
significant thickness are found in the upper portions of the lower McMurray
and are typically removed as waste. In the deepest portions of the mine area,
the lower McMurray is comprised of "water sands". These sands are barren of
bitumen; having never been saturated with bitumen or, in some places,
originally containing bitumen that has since been removed from the sands
through the movement of basal waters over time producing "swept" zones.
The middle McMurray is comprised of thick estuarine channel successions and
tidal flat deposits resulting in interbedded sands and muds. The estuarine
channel sands provide good quality ore. The muddier intervals within the
channels and the tidal flat deposits within the middle McMurray represent
zones of interburden in the mining area.
The upper McMurray consists of shoreface/channel transition deposits and is
typically thin, less than 5 meters. Locally, this member may be entirely
eroded. Exceptional thickness of about 15 meters can be found within the upper
McMurray. In most cases, the bitumen saturation in the upper McMurray is poor
and the material is included with the overburden.
42
FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
HORIZON OIL SANDS PROJECT MINING RESERVES
For the year ended December 31, 2005, the Company retained GLJ to evaluate 100
per cent of phases 1, 2 and 3 of the Horizon Project and prepare an Evaluation
Report on the Company's proved and probable oil sands mining reserves
incorporating both the mining and upgrading projects. These reserves were
evaluated adhering to the requirements of SEC Industry Guide 7 using constant
pricing and have been disclosed separately from the Company's conventional
proved and probable crude oil, NGL and natural gas reserves.
The pit limits and mine plans were updated in 2005 incorporating the results
from the most recent and past drilling programs. Figure 3 shows the mining
areas associated with the reserves and Figure 4 shows the drill hole coverage
used to develop the mine plan. The oil sands mining reserves from GLJ's
Evaluation Report are provided in Table 2. The 2.9 million barrels of gross
proved and probable synthetic crude oil reserves shown in the table are
produced from 37 years of projected production from the first three phases of
the project commencing in 2008.
The Reserve Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with GLJ to review the
qualifications of and procedures used by the evaluator in determining the
estimate of the Company's oil sands mining reserves.
43
FIGURE 3 - HORIZON OIL SANDS PROJECT RESOURCE AREAS AND GENERAL LAYOUT
[GRAPHIC OMITTED]
44
FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE
[GRAPHIC OMITTED]
45
OIL SANDS MINING RESERVES
The following table sets out Canadian Natural's reserves of bitumen and
synthetic crude oil from the Horizon Project as of December 31, 2005:
Constant Prices
----------------------------------------------------------------------------------
Bitumen (mmbbl) Synthetic Crude Oil (1) (mmbbl)
Gross (2) Net Gross (2) Net
-------------------- ------------------ ------------------- ------------------
Total proved reserves 2,235 1,848 1,833 1,626
Total proved and probable reserves 3,430 2,848 2,878 2,566
(1) Synthetic crude oil reserves are based on the upgrading of Bitumen using
technologies implemented at the Horizon Project. The reserves shown for
bitumen and synthetic crude oil are not additive.
(2) Gross reserves mean the total remaining recoverable reserves before
consideration of company interests or royalties.
E. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION
The Company's working interest share of crude oil, NGL and natural gas
production and revenues received for the last three financial years is
summarized in the following tables:
YEAR ENDED DECEMBER 31
-------------------------------------------------------------
2005 2004 2003
---- ---- ----
Daily Production, before royalties
Crude Oil and NGLs (bbl/d) 313,168 282,489 242,392
Natural Gas (mmcf/d) 1,439 1,388 1,299
Annual Production, before royalties
Crude Oil and NGLs (mbbl) 114,306 103,391 88,473
Natural Gas (bcf) 525 508 474
46
NETBACKS
INFORMATION BY QUARTER
YEAR 2005 YEAR 2004
------------------------------------------------- ----------------------------------------------
1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR
---- ---- ---- ---- ----- ---- ---- ---- ---- -----
QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- ----- ------- ------- ------- ------- -----
Average Daily Production
Volumes, before royalties
Crude oil and
NGLs (bbl/d) 287,803 289,064 334,724 340,268 313,168 261,286 275,398 297,262 295,704 282,489
Natural Gas (mcf/d) 1,455 1,454 1,423 1,423 1,439 1,294 1,452 1,396 1,410 1,388
PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
Sales Price (1) $ 39.81 $ 42.51 $ 57.35 $ 46.38 $ 46.86 $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99
Royalties $ 3.39 $ 3.33 $ 5.11 $ 3.89 $ 3.97 $ 2.91 $ 3.15 $ 3.59 $ 2.95 $ 3.16
Production Expenses $ 11.30 $ 11.66 $ 11.48 $ 10.33 $ 11.17 $ 9.58 $ 9.92 $ 10.21 $ 10.41 $ 10.05
NETBACK $ 25.12 $ 27.52 $ 40.76 $ 32.16 $ 31.72 $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78
Natural Gas ($mcf)
Sales Price (1) $ 6.68 $ 7.33 $ 8.61 $ 11.67 $ 8.57 $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50
Royalties $ 1.30 $ 1.48 $ 1.93 $ 2.30 $ 1.75 $ 1.27 $ 1.38 $ 1.39 $ 1.34 $ 1.35
Production Expenses $ 0.69 $ 0.71 $ 0.76 $ 0.76 $ 0.73 $ 0.65 $ 0.66 $ 0.71 $ 0.68 $ 0.67
NETBACK $ 4.69 $ 5.14 $ 5.92 $ 8.61 $ 6.09 $ 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) $ 53.14 $ 56.85 $ 66.81 $ 58.87 $ 59.16 $ 40.75 $ 45.28 $ 51.54 $ 48.60 $ 46.71
Royalties $ 5.20 $ 4.55 $ 5.50 $ 4.40 $ 4.90 $ 3.71 $ 3.98 $ 3.99 $ 4.12 $ 3.95
Production Expenses $ 11.58 $ 12.28 $ 11.47 $ 8.90 $ 10.93 $ 9.77 $ 10.36 $ 10.70 $ 11.20 $ 10.53
NETBACK $ 36.36 $ 40.02 $ 49.84 $ 45.57 $ 43.33 $ 27.27 $ 30.94 $ 36.85 $ 33.28 $ 32.23
Heavy Crude Oil ($/bbl)
Sales Price (1) $ 25.21 $ 27.82 $ 47.25 $ 30.27 $ 33.09 $ 27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99
Royalties $ 1.41 $ 2.07 $ 4.83 $ 3.08 $ 2.92 $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 11.00 $ 11.03 $ 11.50 $ 12.18 $ 11.44 $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
Netback $ 12.80 $ 14.72 $ 30.92 $ 15.01 $ 18.73 $ 15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09
NOTE: Pelican Lake crude oil has an API of 12(0) to 17(0), but receives
medium quality crude netbacks due to exceptionally low operating costs
and low royalty rates.
(1) INCLUDING TRANSPORTATION AND EXCLUDING RISK MANAGEMENT ACTIVITIES
47
NETBACKS
INFORMATION BY QUARTER
YEAR 2005 YEAR 2004
------------------------------------------------ ------------------------------------------------
1ST 2ND 3RD 4TH YEAR 1ST 2ND 3RD 4TH YEAR
QUARTER QUARTER QUARTER QUARTER ENDED QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- ------- ------- ------- ------- ------- --------
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $ 45.80 $ 49.78 $ 61.21 $ 52.10 $ 52.35 $ 37.54 $ 41.03 $ 44.89 $ 43.80 $ 41.81
Royalties $ 10.64 $ 8.77 $ 11.49 $ 9.62 $ 10.13 $ 7.20 $ 7.91 $ 8.59 $ 8.76 $ 8.12
Production Expenses 8.30 $ 8.40 $ 9.27 $ 8.60 $ 8.65 $ 7.30 $ 7.74 $ 7.75 $ 7.85 $ 7.66
NETBACK $ 26.86 $ 32.61 $ 40.45 $ 33.88 $ 33.57 $ 23.04 $ 25.38 $ 28.55 $ 27.19 $ 26.03
Heavy Crude Oil ($/bbl)
Sales Price (1) $ 25.21 $ 27.82 $ 47.25 $ 30.27 $ 33.09 $ 27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99
Royalties $ 1.41 $ 2.07 $ 4.83 $ 3.08 $ 2.92 $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 11.00 $ 11.03 $ 11.50 $ 12.18 $ 11.44 $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
NETBACK $ 12.80 $ 14.72 $ 30.92 $ 15.01 $ 18.73 $ 15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09
Natural Gas ($/mcf)
Sales Price (1) $ 6.73 $ 7.38 $ 8.69 $ 11.79 $ 8.65 $ 6.37 $ 6.78 $ 6.36 $ 6.88 $ 6.61
Royalties $ 1.33 $ 1.50 $ 1.96 $ 2.34 $ 1.78 $ 1.33 $ 1.44 $ 1.45 $ 1.39 $ 1.40
Production Expenses $ 0.66 $ 0.68 $ 0.74 $ 0.74 $ 0.71 $ 0.60 $ 0.60 $ 0.63 $ 0.63 $ 0.62
NETBACK $ 4.74 $ 5.20 $ 5.99 $ 8.71 $ 6.16 $ 4.44 $ 4.74 $ 4.28 $ 4.86 $ 4.59
NORTH SEA PRODUCT NETBACKS
Light Oil ($/bbl)
Sales Price (1) $ 59.56 $ 64.81 $ 74.46 $ 66.88 $ 66.57 $ 44.27 $ 49.22 $ 57.39 $ 52.77 $ 51.37
Royalties $ 0.05 $ 0.11 $ 0.12 $ 0.14 $ 0.10 $ 0.06 $ 0.10 $ 0.09 $ 0.08 $ 0.08
Production Expenses $ 14.91 $ 17.41 $ 15.15 $ 12.11 $ 14.94 $ 13.26 $ 13.84 $ 13.88 $ 14.96 $ 14.03
NETBACK $ 44.60 $ 47.29 $ 59.19 $ 54.63 $ 51.53 $ 30.95 $ 35.28 $ 43.42 $ 37.73 $ 37.26
Natural Gas ($/mcf)
Sales Price (1) $ 3.52 $ 3.07 $ 2.64 $ 3.40 $ 3.17 $ 5.08 $ 3.28 $ 3.17 $ 3.26 $ 3.73
Royalties $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ --
Production Expenses $ 2.52 $ 2.92 $ 2.30 $ 1.96 $ 2.44 $ 1.65 $ 1.92 $ 2.48 $ 2.29 $ 2.07
NETBACK $ 1.00 $ 0.15 $ 0.34 $ 1.44 $ 0.73 $ 3.43 $ 1.36 $ 0.69 $ 0.97 $ 1.66
OFFSHORE WEST AFRICA
PRODUCT NETBACKS
Light Oil ($/bbl)
Sales Price (1) $ 62.34 $ 58.24 $ 59.09 $ 60.19 $ 59.91 $ 42.08 $ 49.34 $ 53.86 $ 51.28 $ 49.05
Royalties $ 1.90 $ 1.81 $ 1.54 $ 1.57 $ 1.62 $ 1.28 $ 1.52 $ 1.42 $ 1.52 $ 1.43
Production Expenses $ 11.43 $ 8.47 $ 5.81 $ 5.62 $ 6.50 $ 7.09 $ 7.43 $ 8.05 $ 7.82 $ 7.59
NETBACK $ 49.01 $ 47.96 $ 51.74 $ 53.00 $ 51.79 $ 33.71 $ 40.39 $ 44.39 $ 41.94 $ 40.03
Natural Gas ($/mcf)
Sales Price (1) $ 7.67 $ 6.88 $ 5.52 $ 5.13 $ 5.91 $ 4.80 $ 5.18 $ 6.31 $ 4.73 $ 5.25
Royalties $ 0.23 $ 0.21 $ 0.13 $ 0.14 $ 0.16 $ 0.15 $ 0.16 $ 0.17 $ 0.14 $ 0.15
Production Expenses $ 1.25 $ 1.37 $ 1.09 $ 0.80 $ 1.05 $ 1.23 $ 1.38 $ 1.39 $ 1.31 $ 1.33
NETBACK $ 6.19 $ 5.30 $ 4.30 $ 4.19 $ 4.70 $ 3.42 $ 3.64 $ 4.75 $ 3.28 $ 3.77
NOTE: Pelican Lake crude oil has an API of 12(0) to 17(0), but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rates.
(1) INCLUDING TRANSPORTATION AND EXCLUDING RISK MANAGEMENT ACTIVITIES.
48
NETBACKS
INFORMATION BY QUARTER
YEAR 2003
-------------------------------------------------------------------------
1ST QUARTER 2ND QUARTER 3RD QUARTER 4TH QUARTER YEAR ENDED
----------- ----------- ----------- ----------- ----------
Average Daily Production Volumes
Crude oil and NGLs (bbl/d) 237,560 240,607 247,016 244,262 242,392
Natural Gas (mcf/d) 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 NGLS 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 Crude Oil ($/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 crude oil has an API of 12(0) to 17(0), but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rates.
(1) INCLUDING TRANSPORTATION AND EXCLUDING RISK MANAGEMENT ACTIVITIES.
49
NETBACKS
INFORMATION BY QUARTER
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 Crude Oil ($/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 Crude 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 Crude 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 crude oil has an API of 12(0) to 17(0), but receives medium
quality crude netbacks due to exceptionally low operating costs and low
royalty rates.
Including transportation and excluding risk management activities
50
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
---------------------------------------------------------
2005 2004
Gross Net Gross Net
------------------------ ------------------------
Natural Gas 1,071 890 801 689
Crude Oil 685 627 378 328
Service/Stratigraphic 251 248 339 336
Dry Holes 136 117 106 96
------------------------ ------------------------
Total 2,143 1,882 1,624 1,449
======================== ========================
*Total Success Rate 93% 91%
*excluding service and stratigraphic test wells
51
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
-------------------------------------
2005 2004
---------------- ---------------
Net property (dispositions) acquisitions((1)) (320) 1,835
Land acquisition and retention 254 120
Seismic evaluation 132 89
Well drilling, completion and equipping 2,000 1,394
Pipeline and production facilities 1,295 821
---------------- ---------------
Reserve replacement expenditures 3,361 4,259
---------------- ---------------
Horizon Project:
Phase 1 construction costs 1,329 --
Capitalized interest and other 170 291
---------------- ---------------
Total Horizon Project 1,499 291
---------------- ---------------
Midstream operations 4 16
Abandonments((2)) 46 32
Head office equipment 22 35
---------------- ---------------
Total Net Capital Expenditures 4,932 4,633
================ ===============
(1) Includes Business Combinations.
(2) Abandonments represent expenditures to settle retirement
obligations and have been reflected as capital expenditures in
this table.
52
2005 THREE MONTHS ENDED
-----------------------------------------------------------
($ millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Net property (dispositions) acquisitions((1)) 2 (341) 0 19
Land acquisition and retention 36 52 69 97
Seismic evaluation 41 20 31 40
Well drilling, completion and equipping 634 306 431 629
Pipeline and production facilities 432 283 266 314
------- ------- -------- -------
Reserve replacement expenditures 1,145 320 797 1,099
Horizon Project
Phase 1 construction costs 132 259 432 506
Capitalized interest and other 83 16 20 51
------- ------- -------- -------
Total Horizon Project 215 275 452 557
Midstream operations 4 -- (1) 1
Abandonments((2)) 4 7 19 16
Head office equipment 4 7 5 6
Total Net Capital Expenditures 1,372 609 1,272 1,679
=======================================================
(1) Includes Business Combinations.
(2) Abandonments represent expenditures to settle retirement obligations and
have been reflected as capital expenditures in this table.
2004 THREE MONTHS ENDED
-------------------------------------------------------
($ millions)
CAPITAL EXPENDITURES((1))
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((2))
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.
(2) Abandonments represent expenditures to settle retirement obligations and
have been reflected as capital expenditures in this table.
53
H. UNDEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region non-reserve acreage as at December 31, 2005:
GROSS ACRES NET ACRES
----------- ---------
(thousands) (thousands)
NORTH AMERICA
-------------
Alberta 9,892 8,376
British Columbia 2,645 2,010
Saskatchewan 615 549
Manitoba 11 11
NORTH SEA
---------
United Kingdom 457 352
OFFSHORE WEST AFRICA
--------------------
Cote d'Ivoire 369 274
Gabon 152 152
--------- ---------
Total 14,141 11,724
========= =========
I. DEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2005:
GROSS ACRES NET ACRES
----------- ---------
(thousands) (thousands)
NORTH AMERICA
-------------
Alberta 5,727 4,545
British Columbia 1,111 870
Saskatchewan 341 279
Manitoba 5 5
NORTH SEA
---------
United Kingdom 138 93
OFFSHORE WEST AFRICA
--------------------
Cote d'Ivoire 7 4
--------- ---------
Total 7,329 5,796
========= =========
54
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
------------------------------------
2005 2004
---- ----
($ millions, except per share information)
Revenues (1) (net of royalties) 8,741 6,536
Cash flow from operations 5,021 3,769
Per common share - basic (3) 9.36 7.03
- diluted (3) 9.33 6.98
Net earnings 1,050 1,405
Per common share - basic (3) 1.96 2.62
- diluted (3) 1.95 2.60
Total assets 21,852 18,372
Total long-term debt(2) 3,321 3,538
---------------------------------------------------------
2005 THREE MONTHS ENDED
---------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (1) (net of royalties) 1,734 1,881 2,515 2,611
Net earnings (loss) (424) 219 151 1,104
Per common share - basic (3) (0.79) 0.41 0.28 2.06
- diluted (3) (0.79) 0.41 0.28 2.06
---------------------------------------------------------
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 (3) 0.49 0.48 0.58 1.07
- diluted (3) 0.48 0.48 0.57 1.06
(1) Excluding transportation costs and risk management activities.
(2) Excluding current portion of long-term debt.
(3) Restated to reflect two-for-one-share split in May 2005.
55
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, we are under no obligation to update this Annual Information Form.
The Company's senior unsecured long-term debt securities are rated "Baa1" with
a stable trend 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 rating outlook to
the Company and not to individual debt instruments. S&P has assigned a
negative outlook to the Company.
Rated Debt Issuances
$125 CAD million 7.40% unsecured note due 2007
$400 CAD million 4.95% unsecured note due 2015
$93 US million 6.45% adjustable rate note due 2009
$400 US million 6.70% unsecured note due 2011
$350 US million 5.45% unsecured note due 2012
$350 US million 4.90% unsecured note due 2014
$400 US million 7.20% unsecured note due 2032
$350 US million 6.54% unsecured note due 2033
$350 US million 5.85% unsecured note due 2035
56
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.
57
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES
The Company's common shares are listed and posted for trading on Toronto Stock
Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the symbol
CNQ.
2005 Monthly Historical Trading on Toronto Stock Exchange
Month High Low Close Volume Traded
January $55.70 $48.55 $54.74 23,564,720
February 74.25 54.60 70.09 31,090,409
March 74.75 63.79 68.36 29,853,739
April 71.88 61.07 62.40 27,675,887
May 1 - 17 71.09 61.90 67.00 13,881,359
*May 18 - 31 37.60 33.36 36.25 18,362,198
June 46.98 36.68 44.40 53,797,555
July 51.45 45.52 51.00 52,706,687
August 59.96 50.61 58.47 57,286,467
September 60.00 51.25 52.50 50,127,673
October 53.34 43.55 48.29 66,484,410
November 58.24 48.25 52.87 55,369,037
December 62.00 53.31 57.63 31,725,589
* Shares began trading on a post two-for-one subdivision basis on May 18, 2005.
On January 22, 2003, the Company announced its intention to make a Normal
Course Issuer Bid through the facilities of TSX and the NYSE, 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 TSX and the NYSE, commencing
January 24, 2004 and ending January 23, 2005, to purchase for cancellation up
to 6,690,385 (13,380,770 post May 21, 2004 two-for-one stock split) common
shares of the Company, being 5 per cent of the 133,807,695 (267,615,390 post
May 21, 2004 two-for-one stock split) 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.
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 (26,818,012 post May 20, 2005
two-for-one stock split) common shares of the Company, being 5 per cent of the
268,180,123 (536,360,246 post May 20, 2005 two-for-one stock split) common
58
shares of the Company outstanding on January 12, 2005. Under this program, the
Company purchased a total of 850,000 common shares for cancellation at a
weighted average purchase price of $53.26 for each common share purchased;
$53.29 after costs.
At the Annual and Special Meeting of Shareholders held May 5, 2005, 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 20, 2005.
On January 20, 2006, the Company announced its intention to make a Normal
Course Issuer Bid through the facilities of TSE and the NYSE, commencing
January 24, 2006 and ending January 23, 2007, to purchase for cancellation up
to 26,852,545 common shares of the Company, being 5 per cent of the
537,050,902 common shares of the Company outstanding on January 17, 2006. As
of the date of this Annual Information Form, no shares have been purchased.
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 regular quarterly dividends. 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 and May 2005 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.
2005 2004 2003
---- ---- ----
Cash dividends declared per common share $0.24 $0.20 $0.15
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.
59
DIRECTORS AND 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:
---------------------------------------------------------------------------------------------------------------------
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
---------------------------------------------------------------------------------------------------------------------
Catherine M. Best Director(2) (4) Executive Vice-President, Risk Management and Chief
Calgary, Alberta (age 52) Financial Officer of Financial Officer of the Calgary
Canada Health Region from 2002 the Calgary Health to present;
Vice-President, Corporate Services and Chief 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
of the Company since November 2003.
N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (a private
Calgary/Banff, Alberta Director(3) management and consulting company). Has served
Canada (age 46) continuously as a director of the Company since September
1988. Currently serving on the board of directors of
Ensign Energy Services Inc. and Magellan Aerospace
Corporation.
Honourable Gary A. Filmon Director (1)(2) Consultant, Exchange Group (business consulting firm
Winnipeg, Manitoba (age 63) based in Winnipeg, Manitoba). Prior thereto, served as
Canada Premier of Manitoba from 1988 to 1999. Has served
continuously as a director of the Company since February
2006. Currently serving on the board of directors of
Manitoba Telecom Services Inc., Pollard Banknote Income
Fund, Arctic Glacier Income Trust, Exchange Industrial
Income Fund, and as a member of the Advisory Board of
Marsh Canada.
Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm)
Atlanta, Georgia (age 56) 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 Vice-Chairman and Officer of the Company. Has served continuously as a
Calgary, Alberta Director director of the Company since June 1982.
Canada (age 60)
Keith A.J. MacPhail Director(3)(5) Chairman, President and Chief Executive Officer, Bonavista
Calgary, Alberta (age 49) 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 Energy Trust and NuVista Energy
Ltd.
Allan P. Markin Chairman and Director(5) Chairman of the Company. Has served continuously as a
Calgary, Alberta (age 60) director of the Company since January 1989.
Canada
Norman F. McIntyre Director(3)(4)(5) An independent businessman. Prior thereto Executive
Calgary, Alberta (age 60) Vice-President, Petro-Canada from 1995 to 2002 and most
Canada recently President, Petro-Canada 2002 to 2004. Has served
continuously as a director of the Company since July 2005.
Currently serving on the board of directors of Signal
Energy Inc. and Petro Andina Resources, a private company.
60
----------------------------------------------------------------------------------------------------------------------
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
James S. Palmer, C.M., A. O. Director(3)(4)(5) Chairman, Burnet, Duckworth & Palmer LLP (law firm). Has
E., Q.C. (age 77) 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 66) 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., Pheromone
Sciences Corp. and Overlord Financial Inc.
David A. Tuer Director(1)(2)(3) An independent businessman. Chairman, Calgary Health
Calgary, Alberta (age 56) Region since October 2001 and President, Value Creation
Canada Inc. since April 2005. Prior thereto President and Chief
Executive Officer, PanCanadian Energy Corporation and most
recently President and CEO of Hawker Resources Inc.
(independent oil and natural gas company) from January
2003 to March 2005. Has served continuously as a director
of the Company since May 2002. Currently serving on the
board of directors of Sequoia Oil and Gas Trust, Rockwater
Capital Corporation; and, Norquay Capital Corporation.
Steve W. Laut President and Chief Officer of the Company.
Calgary, Alberta Operating Officer
Canada (age 48)
Real M. Cusson Senior Vice-President, Officer of the Company.
Calgary, Alberta Marketing
Canada (age 55)
Real J. H. Doucet Senior Vice-President, Officer of the Company.
Calgary, Alberta Oil Sands
Canada (age 53)
Allen M. Knight Senior Vice-President, Officer of the Company.
Calgary, Alberta International &
Canada Corporate Development
(age 56)
Tim S. McKay Senior Vice-President, Officer of the Company.
Calgary, Alberta Operations
Canada (age 44)
Douglas A. Proll Chief Financial Officer Officer of the Company since April 2001; prior thereto
Calgary, Alberta and Senior Vice President Finance and Treasurer of Renaissance Energy
Canada Vice-President, Finance Ltd. to August 2000 and most recently Vice President
(age 55) Finance and Business Development of Husky Energy Inc. from
August 2000 to February 2001.
Lyle G. Stevens Senior Vice-President, Officer of the Company.
Calgary, Alberta Exploitation
Canada (age 51)
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 53)
61
----------------------------------------------------------------------------------------------------------------------
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
Corey B. Bieber Vice-President, Investor Officer of the Company since April 2005; prior thereto
Calgary, Alberta Relations Director of Corporate Accounting of Enbridge Inc. to March
Canada (age 42) 2001, Treasurer of the Company March 2001 to July 2002 and
most recently Director, Investor Relations of the Company
from July 2002 to April 2005.
Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto
Calgary, Alberta (age 47) 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.
Wayne M. Chorney Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Development Operations Production Manager, Thermal Operations of the Company
Canada (age 46) October 1999 to August 2001, General Manager, Production
of CNR International (U.K.) Limited ("CNRI") a wholly
owned subsidiary of the Company September 2000 to August
2001 and most recently Director, Production Operations of
CNRI August 2001 to April 2004.
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 43)
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 52)
Randall S. Davis Vice-President, Officer of the Company since July 2004; prior thereto
Calgary, Alberta Financial Accounting and Manager, Financial Reporting of the Company to July 2002
Canada Controls and most recently Financial Controller of the Company from
(age 39) July 2002 to July 2004.
Larry C. Galea Vice-President, Officer of the Company since April 2005; prior thereto
Calgary, Alberta Operations Planning Exploitation Manager of the Company to January 2002,
Canada (age 40) Manager, Operations Planning January 2002 to April 2004,
and most recently Exploitation Manager from April 2004 to
April 2005.
Jerome W. Harvey Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Commercial Operations Manager, Commercial Operations.
Canada (age 52)
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 48) 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 38)
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 Project and Offsites Project Manager January 2002 to July 2002,
(age 42) Director, Utilities and Offsites July 2002 to July 2003
and most recently General Manager, Utilities and Offsites
July 2003 to December 2004.
62
----------------------------------------------------------------------------------------------------------------------
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
Philip A. Keele Vice-President, Mining, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Horizon Oil Sands Project from Mine Manager at Fording Coal Limited to February
Canada (age 46) 2001, Chief Mine Engineer of the Company February 2001 to
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 38) recently Manager, Field Operations of the Company from
April 2000 to September 2002.
Leon Miura Vice-President, Upgrading Officer of the Company since August 2003; prior thereto
Calgary, Alberta (age 51) held progressively senior positions at Petroleos de Canada
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 44) 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 July
Canada (age 44) 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 39)
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 59) President of 960925 Alberta Ltd. from November 2001 to
April 2002, Manager, Site Development of the Company from
May 2002 to December 2002 and most recently General
Manager Site Development of the Company from January 2003
to April 2004.
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 38) 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 44) 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 49) 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.
63
----------------------------------------------------------------------------------------------------------------------
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
----------------------------------------------------------------------------------------------------------------------
Kimberly I. McKay Treasurer Officer of the Company since December 2004; prior thereto
Calgary, Alberta (age 37) 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 56)
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 Canadian
Natural shareholders. With the exception of Messrs. N. F. McIntyre and G. A.
Filmon who were appointed to the Board effective July 29, 2005 and February
21, 2006 respectively, all of the current directors were elected to the Board
at the last annual meeting of shareholders held on May 5, 2005. All of the
current directors are standing for election at the Annual General Meeting of
Shareholders scheduled for May 4, 2006.
As at December 31, 2005, 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 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).
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
No, director, executive officer or principal shareholder of Canadian Natural,
or associate or affiliate of those persons, has any material interest, direct
or indirect, in any transaction within the last three years that has
materially affected or will materially affect the Company.
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. A. Filmon, G. D. Giffin and D. A. Tuer each
of whom is independent and financially literate as those terms are defined
64
under Canadian securities regulations MI 52-110 and the NYSE listing standards
as they pertain to audit committees of listed issuers. The education and
experience of each member of the Audit Committee relevant to their
responsibilities as an Audit Committee member is described below.
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.
Honourable G. A. Filmon holds both a Bachelor of Science degree and a Master
of Science degree in Civil Engineering. He was Premier of the Province of
Manitoba for several years and during that time chaired the Treasury Board for
a period of five years. He was President of Success Commercial College for 11
years and is currently a business management consultant. Mr. G. A. Filmon is a
director of other public companies and is an active member of other audit
committees, one of which he chairs.
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.
The Audit Committee in 2005 approved specified audit and non-audit services to
be performed by PricewaterhouseCoopers LLP ("PwC") the independent auditor of
the Corporation. The following table lists the fees accrued to PwC for fiscal
year 2005.
AUDITOR SERVICE FEES
AUDITOR SERVICE 2005 2004
--------------- ---- ----
Audit fees $1,200,235 $1,100,548
Audit related fees $ 266,923 $ 183,663
Tax related fees $ 39,331 $ 39,330
All other fees $ 7,290 $ 0
-----------------------------------------------------------------
Total Accrued Fees $1,513,779 $1,323,541
=================================================================
The Charter of the Audit Committee of the Company is attached as Schedule "C"
to this Annual Information Form.
65
LEGAL PROCEEDINGS
From time to time, Canadian Natural 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.
MATERIAL CONTRACTS
Other than contracts entered into in the ordinary course of business, the
Company has not entered into any material contracts in the most recently
completed financial year nor has it entered into any material contracts before
the most recently completed financial year and which are still in effect.
INTERESTS OF EXPERTS
PricewaterhouseCoopers LLP, Chartered Accountants, are the Company's auditors
and such firm has prepared an opinion with respect to the Company's
consolidated financial statements as at and for the year ended December 31,
2005. PricewaterhouseCoopers LLP is independent in accordance with the Rules
of Professional Conduct as outlined by the Institute of Chartered Accountants
of Alberta.
Sproule Associates Limited, Ryder Scott Company and GLJ Petroleum Consultants
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 GLJ Petroleum Consultants 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 General
Meeting and Information Circular dated March 15, 2006 in connection with the
Annual General Meeting of Shareholders of Canadian Natural to be held on May
4, 2006 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, 2005 found on pages 45 to
73, 74 to 96 and 97 to 101 respectively, of the 2005 Annual Report to the
Shareholders, which information is incorporated herein by reference.
66
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
67
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. We have evaluated the Corporation's reserves data as at December 31,
2005. The reserves data consist of the following:
(a) (i) proved conventional crude oil, natural gas liquids and natural
gas reserve quantities estimated as at December 31, 2005 using
constant prices and costs;
(ii) the related estimated net present value; and
(iii) the related standardized measure calculation for proved
conventional crude oil, natural gas liquids and natural gas
reserve quantities.
(b) (i) both proved, and proved and probable conventional crude oil,
natural gas liquids and natural gas reserve quantities
estimated as at December 31, 2005 using forecast prices and
costs; and
(ii) the related estimated net present value.
(c) (i) both proved, and proved and probable bitumen and synthetic
crude oil reserve quantities relating to surface mineable oil
sands projects estimated as at December 31, 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
conventional reserves (before deduction of income taxes) attributed to
proved conventional crude oil, NGL and natural gas reserves quantities,
estimated using constant prices and costs and calculated using a
68
discount rate of 10 percent, included in the reserves data of the
Corporation evaluated by us for the year ended December 31, 2005, and
identifies the respective portions thereof that we have evaluated and
reported on to the Corporation's management and board of directors:
---------------------------------------------------------------------------------------------------------------------
INDEPENDENT DESCRIPTION AND LOCATION OF RESERVES
QUALIFIED PREPARATION (COUNTRY OR FOREIGN
RESERVES DATE OF GEOGRAPHIC AREA) NET PRESENT VALUES OF CONVENTIONAL RESERVES
EVALUATOR OR EVALUATION
AUDITOR REPORT (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
---------------------------------------------------------------------------------------------------------------------
AUDITED EVALUATED REVIEWED TOTAL
MM$ MM$ MM$ MM$
---------------------------------------------------------------------------------------------------------------------
Sproule Sproule Canada, USA $0 $20,727 $0 $20,727
Associates Ltd. Evaluated the
P&NG Reserves
as reported
February 7,
2006.
---------------------------------------------------------------------------------------------------------------------
Ryder Scott Ryder Scott United Kingdom and $0 $ 9,890 $0 $ 9,890
Company Evaluated the Offshore West Africa
P&NG Reserves
as reported
February 7,
2006.
---------------------------------------------------------------------------------------------------------------------
TOTALS $0 $30,617 $0 $30,617
---------------------------------------------------------------------------------------------------------------------
In addition, both proved, and proved and probable reserves have been evaluated
for oil sands mining properties located in Canada. The Horizon Project
reserves were evaluated as at December 31, 2005. GLJ Petroleum Consultants
("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 disclosed separately from the Company's conventional crude oil and
natural 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.
7. We have no responsibility to update our evaluation for events and
circumstances occurring after their respective preparation dates.
69
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 7, 2006
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
GLJ PETROLEUM CONSULTANTS
ORIGINAL SIGNED BY:
/s/ James H. Willmon
-------------------------
James H. Willmon, P.Eng.
Vice-President
70
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 conventional crude oil, 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 conventional crude oil, NGLs and natural gas reserve
quantities estimated as at December 31, 2005 using constant
prices and costs;
(ii) the related estimated net present value; and
(iii) the related standardized measure calculation for proved
conventional crude oil, NGL and natural gas reserve quantities.
(b) (i) both proved, and proved and probable conventional crude oil,
NGL and natural gas reserve quantities estimated as at December
31, 2005 using forecast prices and costs;
(ii) the related estimated net present value; and,
(c) (i) both proved, and proved and probable bitumen and synthetic
crude oil reserve quantities relating to surface mineable oil
sands operations estimated as at December 31, 2005.
Sproule Associates Limited, Ryder Scott Company and GLJ Petroleum Consultants,
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.
71
The Reserves Committee of the Board of Directors has reviewed the
Corporation's procedures for assembling and reporting other information
associated with crude 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 crude 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.
/s/ Steve W. Laut
----------------------
Steve W. Laut
President and Chief Operating Officer
/s/ Douglas A. Proll
----------------------
Douglas A. Proll
Chief Financial Officer and Senior Vice President, Finance
/s/ David A. Tuer
----------------------
David A. Tuer
Independent Director and Chair of the Reserve Committee
/s/ Norman F. McIntyre
----------------------
Norman F. McIntyre
Independent Director and Member of the Reserve Committee
Dated this 21st day of February, 2006
Calgary, Alberta
72
SCHEDULE "C"
CANADIAN NATURAL RESOURCES LIMITED
(THE "CORPORATION")
CHARTER OF THE AUDIT COMMITTEE OF THE BOARD OF DIRECTORS
I AUDIT COMMITTEE PURPOSE
The Audit Committee is appointed by the Board of Directors (the
"Board") to assist the Board in fulfilling its responsibility for the
stewardship of the Corporation in overseeing the business and affairs
of the Corporation. The Audit Committee's primary duties and
responsibilities are to:
1. ensure that the Corporation's management has designed and
implemented an effective system of internal financial controls;
2. monitor and report on the integrity of the Corporation's financial
statements, financial reporting processes and systems of internal
controls regarding financial, accounting and compliance with
regulatory and statutory requirements as they relate to financial
statements, taxation matters and disclosure of material facts;
3. select and recommend for appointment by the shareholders, the
Corporation's independent auditors, pre-approve all audit and
non-audit services to be provided to the Corporation by the
Corporation's independent auditors consistent with all applicable
laws, and establish the fees and other compensation to be paid to
the independent auditors;
4. monitor the independence and performance of the Corporation's
independent auditors;
5. monitor the performance of the internal auditing function;
6. establish procedures for the receipt, retention, response to and
treatment of complaints, including confidential, anonymous
submissions by the Corporation's employees, regarding accounting,
internal controls or auditing matters; and,
7. provide an avenue of communication among the independent auditors,
management, the internal auditing function and the Board.
II AUDIT COMMITTEE COMPOSITION, PROCEDURES AND ORGANIZATION
1. The Audit Committee shall consist of at least three (3) directors
as determined by the Board, each of whom shall be independent,
non-executive directors, free from any relationship that would
interfere with the exercise of his or her independent judgment.
Audit Committee members shall meet the independence and experience
requirements of the regulatory bodies to which the Corporation is
subject to. All members of the Audit Committee shall have a basic
understanding of finance and accounting and be able to read and
understand fundamental financial statements at the time of their
appointment to the Audit Committee. At least one member of the
Audit Committee shall have accounting or related financial
73
management expertise and qualify as a "financial expert" or
similar designation in accordance with the requirements of the
regulatory bodies to which the Corporation may be subject to.
2. The Board at its organizational meeting held in conjunction with
each annual general meeting of the shareholders shall appoint the
members of the Audit Committee for the ensuing year. The Board may
at any time remove or replace any member of the Audit Committee
and may fill any vacancy in the Audit Committee.
3. The Board shall appoint a member of the Audit Committee as chair
of the Audit Committee. If an Audit Committee Chair is not
designated by the Board, or is not present at a meeting of the
Audit Committee, the members of the Audit Committee may designate
a chair by majority vote of the Audit Committee membership.
4. The Secretary or the Assistant Secretary of the Corporation shall
be secretary of the Audit Committee unless the Audit Committee
appoints a secretary of the Audit Committee.
5. The quorum for meetings shall be one half (or where one half of
the members of the Audit Committee is not a whole number, the
whole number which is closest to and less than one half) of the
members of the Audit Committee subject to a minimum of two members
of the Audit Committee present in person or by telephone or other
telecommunications device that permits all persons participating
in the meeting to speak and to hear each other.
6. Meetings of the Audit Committee shall be conducted as follows:
(a) the Audit Committee shall meet at least four (4) times
annually at such times and at such locations as may be
requested by the Chair of the Audit Committee;
(b) the Audit Committee shall meet privately in executive
sessions at each meeting with management, the manager of
internal auditing, the independent auditors, and as a
committee to discuss any matters that the Audit Committee or
each of these groups believe should be discussed.
7. The independent auditors and internal auditors shall have a direct
line of communication to the Audit Committee through its chair and
may bypass management if deemed necessary. Any employee may bring
before the Audit Committee directly and may bypass management if
deemed necessary any matter involving questionable, illegal or
improper financial practices or transactions.
III AUDIT COMMITTEE DUTIES AND RESPONSIBILITIES
1. The overall duties and responsibilities of the Audit Committee
shall be as follows:
a. to assist the Board in the discharge of its responsibilities
relating to the Corporation's accounting principles,
reporting practices and internal controls and its approval
of the Corporation's annual and quarterly consolidated
financial statements;
74
b. to establish and maintain a direct line of communication
with the Corporation's internal auditors and independent
auditors and assess their performance;
c. to ensure that the management of the Corporation has
designed, implemented and is maintaining an effective system
of internal controls;
d. to report regularly to the Board on the fulfillment of its
duties and responsibilities; and,
e. to review annually the Audit Committee Charter and recommend
any changes to the Nominating and Corporate Governance
Committee for approval by the Board.
2. The duties and responsibilities of the Audit Committee as they
relate to the independent auditors shall be as follows:
a. to select and recommend for appointment by the shareholders,
the Corporation's independent auditors, review the
independence and performance of the independent auditors and
approve any discharge of auditors when circumstances
warrant;
b. to approve the fees and other significant compensation to be
paid to the independent auditors, scope and timing of the
audit and other related services rendered by the independent
auditors;
c. to approve the independent auditor's annual audit plan,
including scope, staffing, locations and reliance upon
management and internal audit department prior to the
commencement of the audit;
d. to approve proposed non-audit services to be provided by the
independent auditors except those non-audit services
prohibited by legislation;
e. on an annual basis, obtain and review a report by the
independent auditors describing (i) the independent
auditor's internal quality control procedures; (ii) any
material issues raised by the most recent quality-control
review, or peer review, of the firm, or by any inquiry or
investigation by governmental or professional authorities
within the preceding five years respecting one or more
independent audits carried out by the firm; and, (iii) any
steps taken to address any such issues arising from the
review, inquiry or investigation, and, receive a written
statement from the independent auditors outlining all
significant relationships they have with the Corporation
that could impair the auditor's independence. The
Corporation's independent auditors may not be engaged to
perform prohibited activities under the Sarbanes-Oxley Act
of 2002 or the rules of the Public Company Accounting
Oversight Board or other regulatory bodies, which the
Corporation is governed by;
f. to review and discuss with the independent auditors, upon
completion of their audit and prior to the filing or
releasing annual financial statements:
(i) contents of their report, including :
75
(a) all critical accounting policies and practices
used;
(b) all alternative treatments of financial
information within GAAP that have been discussed
with management, ramifications of the use of
such treatments and the treatment preferred by
the independent auditor;
(c) other material written communications between
the independent auditor and management;
(ii) scope and quality of the audit work performed;
(iii) adequacy of the Corporation's financial and auditing
personnel;
(iv) cooperation received from the Corporation's personnel
during the audit;
(v) internal resources used;
(vi) significant transactions outside of the normal
business of the Corporation;
(vii) significant proposed adjustments and recommendations
for improving internal accounting controls,
accounting principles or management systems;
(viii) the non-audit services provided by the independent
auditors; and,
(ix) consider the independent auditor's judgments about
the quality and appropriateness of the Corporation's
accounting principles and critical accounting
estimates as applied in its financial reporting; and,
g. to review and approve a report to shareholders as required,
to be included in the Corporation's Information Circular and
Proxy Statement, disclosing any non-audit services approved
by the Audit Committee.
3. The duties and responsibilities of the Audit Committee as they
relate to the internal auditors shall be as follows:
a. to review the budget, internal audit function with respect
to the organization structure, staffing, effectiveness and
qualifications of the Corporation's internal audit
department;
b. to review and approve the internal audit plan; and
c. to review significant internal audit findings and
recommendations together with management's response and
follow-up thereto.
4. The duties and responsibilities of the Audit Committee as they
relate to the internal control procedures of the Corporation shall
be as follows:
a. to review the appropriateness and effectiveness of the
Corporation's policies and business practices which impact
on the financial integrity of the Corporation, including
those relating to internal auditing, insurance, accounting,
information services and systems and financial controls,
management reporting and risk management;
b. to review any unresolved issues between management and the
independent auditors that could affect the financial
reporting or internal controls of the Corporation; and
76
c. to periodically review the Corporation's financial and
auditing procedures and the extent to which recommendations
made by the internal audit staff or by the independent
auditors have been implemented.
5. Other duties and responsibilities of the Audit Committee shall be
as follows:
a. to review the Corporation's unaudited quarterly consolidated
financial statements and related Management Discussion &
Analysis including the impact of unusual items and changes
in accounting principles and estimates and report to the
Board with respect thereto;
b. to review the Corporation's audited annual consolidated
financial statements and related Management Discussion &
Analysis including the impact of unusual items and changes
in accounting principles and estimates and report to the
Board with respect thereto;
c. to review and approve regulatory filings and decisions as
they relate to the Corporation's consolidated financial
statements and related Management Discussion & Analysis and
report to the Board thereto with respect to:
(i) the annual report to shareholders;
(ii) the annual information form;
(iii) the annual information form on Form 40-F;
(iv) prospectuses; and,
(v) other disclosure reports requiring approval by the
Board;
d. to review the appropriateness of the policies and procedures
used in the preparation of the Corporation's consolidated
financial statements and other required disclosure documents
and consider recommendations for any material change to such
policies;
e. to review with management, the independent auditors and if
necessary with legal counsel, any litigation, claim or other
contingency, including tax assessments that could have a
material affect upon the financial position or operating
results of the Corporation and the manner in which such
matters have been disclosed in the consolidated financial
statements;
f. to co-ordinate meetings with the Reserves Committee of the
Corporation, the Corporation's senior engineering
management, independent evaluating engineers and auditors as
required and consider such further inquiries as are
necessary to approve the consolidated financial statements;
g. to develop a calendar of activities to be undertaken by the
Audit Committee for each ensuing year and to submit the
calendar in the appropriate format to the Board following
each annual general meeting of shareholders;
h. to perform any other activities consistent with this
Charter, the Corporation's By-laws and governing law, as the
Audit Committee or the Board deems necessary or appropriate;
and,
77
i. to maintain minutes of meetings and to report on a regular
basis to the Board on significant results of the foregoing
activities.
The Audit Committee has the authority to conduct any investigation appropriate
to fulfilling its responsibilities, and it has direct access to the
independent auditors as well as officers and employees of the Corporation. The
Audit Committee has the authority to retain, at the Corporation's expense,
special legal, accounting or other consultants or experts it deems necessary
in the performance of its duties. The Corporation shall at all times make
adequate provisions for the payment of all fees and other compensation
approved by the Audit Committee, to the Company's independent auditors in
connection with the issuance of its audit report, or to any consultants or
experts employed by the Audit Committee.
==============================================================================
THE PREMIUM VALUE,
DEFINED GROWTH, INDEPENDENT
[GRAPIC OMITTED]
[LOGO - CANADIAN NATURAL]
2005 ANNUAL REPORT
==============================================================================
M A N A G E M E N T'S R E P O R T
The accompanying consolidated financial statements and all information in the
annual report are the responsibility of management. The consolidated financial
statements have been prepared by management in accordance with the accounting
policies in the notes to the consolidated financial statements. Where
necessary, management has made informed judgements and estimates in accounting
for transactions that were not complete at the balance sheet date. In the
opinion of management, the financial statements have been prepared in
accordance with Canadian generally accepted accounting principles appropriate
in the circumstances. The financial information elsewhere in the annual report
has been reviewed to ensure consistency with that in the consolidated
financial statements.
Management maintains appropriate systems of internal control. Policies and
procedures are designed to give reasonable assurance that transactions are
appropriately authorized, assets are safeguarded from loss or unauthorized use
and financial records are properly maintained to provide reliable information
for preparation of financial statements.
PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has
been engaged, as approved by a vote of the shareholders at the Company's most
recent Annual General Meeting, to examine the consolidated financial
statements in accordance with generally accepted auditing standards in Canada
and provide an independent professional opinion. Their report is presented
with the consolidated financial statements.
The Board of Directors (the "Board") is responsible for ensuring that
management fulfills its responsibilities for financial reporting and internal
controls. The Board exercises this responsibility through the Audit Committee
of the Board. This committee, which is comprised of non-management directors,
meets with management and the external auditors to satisfy itself that
management responsibilities are properly discharged and to review the
consolidated financial statements before they are presented to the Board for
approval. The consolidated financial statements have been approved by the
Board on the recommendation of the Audit Committee.
/s/ Steve W. Laut /s/ Douglas A. Proll /s/ Randall S. Davis
-------------------- ----------------------- -----------------------
Steve W. Laut Douglas A. Proll CA Randall S. Davis CA
President & Chief Senior Vice President, Finance & Vice President, Financial
Operating Officer Chief Financial Officer Accounting & Controls
February 21, 2006
A U D I T O R'S R E P O R T
TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED,
We have audited the consolidated balance sheets of Canadian Natural Resources
Limited as at December 31, 2005 and 2004 and the consolidated statements of
earnings, retained earnings and cash flows for each of the years in the three
year period ended December 31, 2005. These consolidated financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted
auditing standards. Those standards require that we plan and perform an audit
to obtain reasonable assurance whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation.
In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31,
2005 and 2004 and the results of its operations and its cash flows for each of
the years in the three year period ended December 31, 2005 in accordance with
Canadian generally accepted accounting principles.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
February 21, 2006
COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the addition of
an explanatory paragraph (following the opinion paragraph) when there is a
change in accounting principles that has a material effect on the
comparability of the Company's consolidated financial statements, such as the
change described in Note 10 to the consolidated financial statements. Our
report to the shareholders dated February 21, 2006 is expressed in accordance
with Canadian reporting standards which do not require a reference to such a
change in accounting principles in the Auditors' report when the change is
properly accounted for and adequately disclosed in the consolidated financial
statements.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
February 21, 2006
74 Management and Auditors' Reports
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------
As at DECEMBER 31
(millions of Canadian dollars) 2005 2004
----------------------------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 18 $ 28
Accounts receivable and other 1,546 1,055
Future income tax (note 6) 487 83
Current portion of other long-term assets (note 2) - 34
----------------------------------------------------------------------------------------------
2,051 1,200
Property, plant and equipment (note 3) 19,694 17,064
Other long-term assets (note 2) 107 108
----------------------------------------------------------------------------------------------
$ 21,852 $ 18,372
==============================================================================================
LIABILITIES
Current liabilities
Accounts payable $ 573 $ 379
Accrued liabilities 1,781 1,019
Current portion of long-term debt (note 4) - 194
Current portion of other long-term liabilities (note 5) 1,471 260
----------------------------------------------------------------------------------------------
3,825 1,852
Long-term debt (note 4) 3,321 3,538
Other long-term liabilities (note 5) 1,434 1,208
Future income tax (note 6) 5,035 4,450
----------------------------------------------------------------------------------------------
13,615 11,048
----------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 7) 2,442 2,408
Retained earnings 5,804 4,922
Foreign currency translation adjustment (note 8) (9) (6)
----------------------------------------------------------------------------------------------
8,237 7,324
----------------------------------------------------------------------------------------------
$ 21,852 $ 18,372
==============================================================================================
COMMITMENTS (note 11)
Approved by the Board of Directors:
/s/ Catherine M. Best /s/ N. Murray Edwards
-------------------------- --------------------------
Catherine M. Best N. Murray Edwards
Chair of the Audit Committee Vice-Chairman of the Board of Directors
and Director and Director
Consolidated Financial Statements 75
CONSOLIDATED STATEMENTS OF EARNINGS
-----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars, except per common share amounts) 2005 2004 2003
-----------------------------------------------------------------------------------------------------------
Revenue $ 10,107 $ 7,547 $ 6,155
Less: royalties (1,366) (1,011) (872)
-----------------------------------------------------------------------------------------------------------
Revenue, net of royalties 8,741 6,536 5,283
-----------------------------------------------------------------------------------------------------------
Expenses
Production 1,663 1,400 1,209
Transportation 270 250 262
Depletion, depreciation and amortization 2,013 1,769 1,509
Asset retirement obligation accretion (note 5) 69 51 62
Administration 151 125 87
Stock-based compensation (note 5) 723 249 200
Interest, net 149 189 201
Risk management activities (note 10) 1,952 434 148
Foreign exchange gain (132) (91) (335)
-----------------------------------------------------------------------------------------------------------
6,858 4,376 3,343
-----------------------------------------------------------------------------------------------------------
Earnings before taxes 1,883 2,160 1,940
Taxes other than income tax (note 6) 194 165 107
Current income tax (note 6) 286 116 92
Future income tax (note 6) 353 474 338
-----------------------------------------------------------------------------------------------------------
Net earnings $ 1,050 $ 1,405 $ 1,403
-----------------------------------------------------------------------------------------------------------
Net earnings per common share (note 9)
Basic $ 1.96 $ 2.62 $ 2.62
Diluted $ 1.95 $ 2.60 $ 2.53
===========================================================================================================
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
-----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars) 2005 2004 2003
-----------------------------------------------------------------------------------------------------------
Balance - beginning of year $ 4,922 $ 3,650 $ 2,424
Net earnings 1,050 1,405 1,403
Dividends on common shares (note 7) (127) (107) (81)
Purchase of common shares under Normal Course Issuer Bid (note 7) (41) (26) (96)
-----------------------------------------------------------------------------------------------------------
Balance - end of year $ 5,804 $ 4,922 $ 3,650
===========================================================================================================
76 Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
----------------------------------------------------------------------------------------------------------
For the years ended December 31
(millions of Canadian dollars) 2005 2004 2003
----------------------------------------------------------------------------------------------------------
Operating activities
Net earnings $ 1,050 $ 1,405 $ 1,403
Non-cash items
Depletion, depreciation and amortization 2,013 1,769 1,509
Asset retirement obligation accretion 69 51 62
Stock-based compensation 723 249 200
Unrealized risk management activities 925 (40) -
Unrealized foreign exchange gain (103) (94) (343)
Deferred petroleum revenue tax recovery (9) (45) (9)
Future income tax 353 474 338
Deferred charges (31) (33) 10
Abandonment expenditures (46) (32) (40)
Net change in non-cash working capital (note 12) (147) (14) (48)
----------------------------------------------------------------------------------------------------------
4,797 3,690 3,082
----------------------------------------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit facilities (435) 357 (647)
Issue (repayment) of medium-term notes 400 (125) -
Repayment of senior unsecured notes (194) (54) (85)
Repayment of preferred securities (107) - -
Issue of US dollar debt securities - 830 -
Repayment of obligations under capital leases - (7) (8)
Dividends on common shares (121) (101) (77)
Issue of common shares on exercise of stock options 9 24 89
Purchase of common shares (45) (33) (144)
Net change in non-cash working capital (note 12) 19 6 (11)
----------------------------------------------------------------------------------------------------------
(474) 897 (883)
----------------------------------------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and equipment (5,340) (4,582) (2,486)
Net proceeds on sale of property, plant and equipment 454 7 20
----------------------------------------------------------------------------------------------------------
Net expenditures on property, plant and equipment (4,886) (4,575) (2,466)
Net proceeds on sale of other assets 11 - -
Net change in non-cash working capital (note 12) 542 (88) 341
----------------------------------------------------------------------------------------------------------
(4,333) (4,663) (2,125)
----------------------------------------------------------------------------------------------------------
(Decrease) increase in cash (10) (76) 74
Cash - beginning of year 28 104 30
----------------------------------------------------------------------------------------------------------
Cash - end of year $ 18 $ 28 $ 104
==========================================================================================================
Consolidated Financial Statements 77
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in millions of Canadian dollars, unless otherwise stated)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior independent
crude oil and natural gas exploration, development and production company
head-quartered in Calgary, Alberta, Canada. The Company's operations are
focused in North America, largely in western Canada, the United Kingdom
portion of the North Sea and Offshore West Africa. Within western Canada, the
Company is developing its Horizon Oil Sands Project (the "Horizon Project")
and maintains its midstream activities. The Horizon Project involves a plan to
recover bitumen through mining operations, while the midstream activities
include the Company's pipeline operations and an electricity co-generation
system.
The consolidated financial statements of the Company have been prepared in
accordance with accounting principles generally accepted in Canada ("Canadian
GAAP"). A summary of differences between accounting principles in Canada and
those generally accepted in the United States ("US GAAP") is contained in note
15.
Significant accounting policies are summarized as follows:
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
all of its subsidiaries and partnerships. A significant portion of the
Company's activities are conducted jointly with others and the consolidated
financial statements reflect only the Company's proportionate interest in such
activities.
(B) MEASUREMENT UNCERTAINTY
Management has made estimates and assumptions regarding certain assets,
liabilities, revenues and expenses in the preparation of the consolidated
financial statements. Such estimates primarily relate to unsettled
transactions and events as of the date of the consolidated financial
statements. Accordingly, actual results may differ from estimated amounts.
Depletion, depreciation and amortization, and amounts used for ceiling test
calculations are based on estimates of crude oil and natural gas reserves and
commodity prices, production expenses and capital costs required to develop
and produce those reserves. Substantially all of the Company's reserve
estimates are evaluated annually by independent engineering firms. By their
nature, estimates of reserves and the related future cash flows are subject to
measurement uncertainty, and the impact of differences between actual and
estimated amounts on the consolidated financial statements of future periods
could be material.
The calculation of asset retirement obligations includes estimates of the
future costs to settle the asset retirement obligation, the timing of the cash
flows to settle the obligation, and the future inflation rates. The impact of
differences between actual and estimated costs, timing and inflation on the
consolidated financial statements of future periods could be material.
The measurement of petroleum revenue tax expense and the related provision in
the consolidated financial statements are subject to uncertainty associated
with future recoverability of crude oil and natural gas reserves, commodity
prices and the timing of future events, which could result in material changes
to deferred amounts.
(C) CASH AND CASH EQUIVALENTS
Cash comprises cash on hand and demand deposits. Other investments (term
deposits and certificates of deposit) with an original term to maturity of
three months or less are reported as cash equivalents on the balance sheet.
(D) PROPERTY, PLANT AND EQUIPMENT
The Company follows the full cost method of accounting for crude oil and
natural gas properties and equipment as prescribed by the Canadian Institute
of Chartered Accountants ("CICA"). Accordingly, all costs relating to the
exploration for and development of crude oil and natural gas reserves are
capitalized and accumulated in country-by-country cost centres. Administrative
overhead incurred during the development phase of large capital projects is
capitalized until the projects are available for their intended use. Proceeds
on disposal of properties are ordinarily deducted from such costs without
recognition of profit or loss except where such disposal constitutes a
significant portion of the Company's reserves in that country.
Contractual arrangements that meet the definition of a lease as specified in
Emerging Issues Committee ("EIC") 150 - "Determining Whether an Arrangement
Contains a Lease" are accounted for as capital leases or operating leases as
appropriate.
78 Notes to the Consolidated Financial Statements
For mining activities, property acquisition, construction and development
costs are capitalized. The Company reviews the recoverability of the carrying
amount of its mining properties when events or circumstances indicate that the
carrying amounts may not be recoverable.
(E) DEPLETION, DEPRECIATION AND AMORTIZATION
Costs related to each cost centre are depleted on the unit-of-production
method based on the estimated proved reserves of that country. Volumes of net
production and net reserves before royalties are converted to equivalent units
on the basis of estimated relative energy content. In determining its
depletion base, the Company includes estimated future costs to be incurred in
developing proved reserves and excludes the cost of unproved properties and
major development projects. Unproved properties are assessed periodically to
determine whether impairment has occurred. When proved reserves are assigned
or the value of unproved property is considered to be impaired, the cost of
the unproved property or the amount of the impairment is added to costs
subject to depletion. Certain costs for major development projects are not
subject to depletion until the projects are available for their intended uses.
Processing and production facilities are depreciated on a straight-line basis
over their estimated lives.
The Company reviews the carrying amount of its crude oil and natural gas
properties ("the properties") relative to their recoverable amount ("the
ceiling test") for each cost centre at each annual balance sheet date, or more
frequently if circumstances or events indicate impairment may have occurred.
The recoverable amount is calculated as the undiscounted cash flow from the
properties using proved reserves and expected future prices and costs. If the
carrying amount of the properties exceeds their recoverable amount, an
impairment loss is recognized in depletion equal to the amount by which the
carrying amount of the properties exceeds their fair value. Fair value is
calculated as the cash flow from those properties using proved and probable
reserves and expected future prices and costs, discounted at a risk-free
interest rate.
Midstream assets are depreciated on a straight-line basis over their estimated
lives. The Company reviews the recoverability of the carrying amount of the
midstream assets when events or circumstances indicate that the carrying
amount might not be recoverable. If the carrying amount of the midstream
assets exceeds their recoverable amount, an impairment loss equal to the
amount by which the carrying amount of the midstream assets exceeds their fair
value is recognized in depreciation.
Head office capital assets are amortized on a declining balance basis over
their estimated useful lives.
(F) CAPITALIZED INTEREST
Beginning in 2005, following the Board of Directors' approval of the Horizon
Project, the Company commenced capitalization of construction period interest
based on costs incurred and the Company's cost of borrowing. Interest
capitalization will cease once construction is substantially complete and the
Horizon Project is available for its intended use.
(G) DEFERRED CHARGES
Deferred charges primarily include deferred financing costs associated with
the issuance of long-term debt and settlement costs of long-term natural gas
contracts. Deferred charges are amortized over the original term of the
related instrument.
(H) ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset retirement obligations on its resource
properties, facilities, production platforms and gathering system based on
current legislation and industry operating practices. The fair values of asset
retirement obligations related to property, plant and equipment are recognized
as a liability in the period in which they are incurred. Retirement costs
equal to the fair value of the asset retirement obligations are capitalized as
part of the cost of the associated property, plant and equipment and are
amortized to expense through depletion and depreciation over the life of the
asset. The fair value of an asset retirement obligation is estimated by
discounting the expected future cash flows to settle the asset retirement
obligation at the Company's average credit-adjusted risk-free interest rate.
In subsequent periods, the asset retirement obligation is adjusted for the
passage of time and for changes in the amount or timing of the underlying
future cash flows. Actual expenditures are charged against the accumulated
asset retirement obligation as incurred.
(I) FOREIGN CURRENCY TRANSLATION
Foreign operations that are self-sustaining are translated using the current
rate method. Under this method, assets and liabilities are translated to
Canadian dollars from their functional currency using the exchange rate in
effect at the consolidated balance sheet date. Revenues and expenses are
translated to Canadian dollars at the monthly average exchange rates. Gains or
losses on translation are included in the foreign currency translation
adjustment in shareholders' equity in the consolidated balance sheets.
Foreign operations that are integrated are translated using the temporal
method. For foreign currency balances and integrated subsidiaries, monetary
assets and liabilities are translated to Canadian dollars at the exchange rate
in effect at the consolidated balance sheet date. Non-monetary assets and
liabilities are translated at the exchange rate in effect when the assets were
acquired or
Notes to the Consolidated Financial Statements 79
obligations incurred. Revenues and expenses are translated to Canadian dollars
at the monthly average exchange rates. Provisions for depletion, depreciation
and amortization are translated at the same rate as the related items. Gains
or losses on translation are included in the consolidated statement of
earnings.
Gains or losses on the translation of long-term debt denominated in US dollars
are either recognized in net earnings immediately, or in the foreign currency
translation adjustment (note 8) for translation gains or losses for that
portion of the US dollar denominated debt designated as a hedge of
self-sustaining foreign operations.
(J) REVENUE RECOGNITION
Revenue from the production of crude oil and natural gas is recognized when
title passes to the customer and delivery has taken place. The Company
assesses customer creditworthiness, both before entering into contracts and
throughout the revenue recognition process.
Revenue as reported represents the Company's share and is presented before
royalty payments to governments and other mineral interest owners. Revenue,
net of royalties represents the Company's share after royalty payments to
governments and other mineral interest owners.
(K) TRANSPORTATION COSTS
Transportation costs incurred to transport crude oil and natural gas to
customers are recorded as a separate cost in the consolidated statement of
earnings.
(L) PRODUCTION SHARING CONTRACT
Production generated from Offshore West Africa is currently shared under the
terms of various Production Sharing Contracts ("PSC"). Revenues are divided
into cost recovery revenues and profit revenues. Cost recovery revenues allow
the Company to recover its share and the government's share of capital and
operating costs carried by the Company. Profit revenues are allocated to the
Company in accordance with its respective equity interest, after a portion has
been allocated to the government. Cost recovery and profit revenues are
reported as sales revenues. The government's share of revenues attributable to
the Company's equity interest, except for income tax, is reported as a royalty
expense in accordance with the PSCs.
(M) PETROLEUM REVENUE TAX
The Company accounts for the United Kingdom petroleum revenue tax ("PRT") by
the life-of-the-field method. The total future liability or recovery of PRT is
estimated using current reserves and anticipated sales prices and costs. The
estimated future PRT is apportioned to accounting periods on the basis of
total estimated future operating income. Changes in the estimated total future
PRT are accounted for prospectively.
(N) INCOME TAX
The Company follows the liability method of accounting for income taxes. Under
this method, future income tax assets and liabilities are recognized based on
the estimated tax effects of temporary differences in the carrying value of
assets and liabilities in the consolidated financial statements and their
respective tax bases, using income tax rates substantively enacted on the
consolidated balance sheet date. The effect of a change in income tax rates on
the future income tax assets and liabilities is recognized in net earnings in
the period of the change.
(O) STOCK-BASED COMPENSATION PLANS
The Company accounts for its stock-based compensation plans using the
intrinsic value method. The Company's Stock Option Plan (the "Option Plan")
provides current employees with the right to elect to receive common shares or
direct cash payment in exchange for options surrendered. A liability for
potential cash settlements under the Option Plan is accrued over the vesting
period of the stock options based on the difference between the exercise price
of the stock options and the market price of the Company's common shares. This
liability is revalued at each reporting date to reflect changes in the market
price of the Company's common shares, with the net change recognized in net
earnings, or capitalized during the construction period in the case of the
Horizon Project. When stock options are surrendered for cash, the cash
settlement paid reduces the outstanding liability. When stock options are
exercised for common shares under the Option Plan, consideration paid by
employees and any previously recognized liability associated with the stock
options are recorded as share capital.
The Company has an employee stock savings plan and a stock bonus plan.
Contributions to the employee stock savings plan are recorded as compensation
expense at the time of the contribution. Contributions to the stock bonus plan
are recognized as compensation expense over the related vesting period.
80 Notes to the Consolidated Financial Statements
(P) RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. These derivative
financial instruments are not used for trading or speculative purposes.
Changes in fair value of derivative financial instruments designated as hedges
are not recognized in net earnings until such time as the corresponding gains
or losses on the related hedged items are also recognized. Changes in fair
value of derivative financial instruments not designated as hedges are
recognized in the balance sheet each period with the offset reflected in risk
management activities in the consolidated statements of earnings.
The Company formally documents all hedging transactions at the inception of
the hedging relationship, in accordance with the Company's risk management
policies. The effectiveness of the hedging relationship is evaluated, both at
inception of the hedge and on an ongoing basis.
The Company enters into commodity price contracts to manage anticipated sales
of crude oil and natural gas production in order to protect cash flow for
capital expenditure programs. Gains or losses on these contracts are included
in risk management activities.
The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. Gains or losses on interest
rate swap contracts designated as hedges are included in interest expense.
Gains or losses on non-designated interest rate contracts are included in risk
management activities.
Cross currency swap agreements are periodically used to manage currency
exposure on US dollar denominated long-term debt. The cross currency swap
contracts require the periodic exchange of payments with the exchange at
maturity of notional principal amounts on which the payments are based. Gains
or losses on cross currency swap contracts designated as hedges are included
in interest expense.
Gains or losses on the termination of financial instruments that have been
accounted for as hedges are deferred under other assets or liabilities on the
consolidated balance sheets and amortized into net earnings in the period in
which the underlying hedged transaction is recognized. In the event a
designated hedged item is sold, extinguished or matures prior to the
termination of the related derivative instrument, any unrealized derivative
gain or loss is recognized immediately in net earnings. Gains or losses on the
termination of financial instruments that have not been accounted for as
hedges are recognized in net earnings immediately.
(Q) PER COMMON SHARE AMOUNTS
The Company uses the treasury stock method to determine the dilutive effect of
stock options and other dilutive instruments. This method assumes that
proceeds received from the exercise of in-the-money stock options not included
as a liability are used to purchase common shares at the average market price
during the year. The dilutive effect of convertible securities is calculated
by applying the "if-converted" method, which assumes that the securities are
converted at the beginning of the period and that income items are adjusted to
net earnings.
(R) RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
FINANCIAL INSTRUMENTS
In January 2005, the CICA issued four new standards relating to the accounting
for and disclosure of financial instruments.
o Section 3855 -- "Financial Instruments -- Recognition and
Measurement" prescribes when a financial asset, financial liability,
or non-financial derivative is to be recognized on the balance sheet
as well as its measurement amount. This Section also specifies how
financial instruments gains and losses are to be presented.
Transitional provisions for this Section vary based on the type of
financial instruments under consideration.
o Section 3865 -- "Hedges" expands on existing Accounting Guideline 13
-- "Hedging Relationships," and Section 1650 "Foreign Currency
Translation," by specifying how hedge accounting is to be applied
and what disclosures are necessary when it is applied. Retroactive
application of this Section is not permitted.
o Section 1530 - "Comprehensive Income" introduces new standards for
reporting and disclosure of comprehensive income. Comprehensive
income is the change in equity (net assets) of the Company during a
reporting period from transactions and other events and
circumstances from non-owner sources. It includes all changes in
equity during a period except those resulting from investments by
owners and distributions to owners. Financial statements of prior
periods are required to be restated only for non-financial
instrument items.
o Section 3251 - "Equity" replaces Section 3250 "Surplus" and
establishes standards for the presentation of equity and changes in
equity during a reporting period. Financial statements of prior
periods are required to be restated only for non-financial
instrument items. For all other items, comparative financial
statements presented are not restated, but an adjustment to the
opening balance of accumulated other comprehensive income may be
required.
Notes to the Consolidated Financial Statements 81
The Company plans to adopt these new standards for interim and annual
financial statements effective January 1, 2007. The effect on the Company's
consolidated financial statements cannot be reasonably determined at this time
as the financial derivatives outstanding at December 31, 2006 and their
related fair values are not known.
(S) COMPARATIVE FIGURES
Certain figures provided for prior years have been reclassified to conform to
the presentation adopted in 2005. Common share data has been restated to
reflect the two-for-one share split in May 2005.
2. OTHER LONG-TERM ASSETS
------------------------------------------------------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------------------------------------------------------
Deferred charges $ 107 $ 76
Risk management (note 10) - 66
------------------------------------------------------------------------------------------------------------------------
107 142
Less: current portion - 34
------------------------------------------------------------------------------------------------------------------------
$ 107 $ 108
========================================================================================================================
3. PROPERTY, PLANT AND EQUIPMENT
2005 2004
------------------------------------------------------------------------------------------------------------------------
Accumulated Accumulated
depletion depletion
and and
Cost depreciation Net Cost depreciation Net
------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 22,258 $ 7,948 $ 14,310 $ 19,750 $ 6,356 $ 13,394
North Sea 2,703 1,022 1,681 2,550 727 1,823
Offshore West Africa 1,547 294 1,253 1,091 190 901
Other 27 14 13 22 14 8
Horizon Project 2,169 - 2,169 672 - 672
Midstream 251 48 203 241 32 209
Head office 124 59 65 101 44 57
------------------------------------------------------------------------------------------------------------------------
$ 29,079 $ 9,385 $ 19,694 $ 24,427 $ 7,363 $ 17,064
========================================================================================================================
During the year ended December 31, 2005, the Company capitalized
administrative overhead of $41 million (2004 - $49 million, 2003 - $35
million) relating to exploration and development in the North Sea and Offshore
West Africa and $236 million (2004 - $35 million, 2003 - $23 million) in North
America, primarily related to the Horizon Project.
During the year ended December 31, 2005, the Company capitalized $72 million
(2004 and 2003 - $nil) in construction period interest costs related to the
Horizon Project.
Included in property, plant and equipment are unproved properties and major
development projects that are not subject to depletion or depreciation:
-----------------------------------------------------------------------------------------------------------------------
2005 2004
-----------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 1,372 $ 1,028
North Sea 28 44
Offshore West Africa 182 528
Other 13 8
Horizon Project 2,169 672
-----------------------------------------------------------------------------------------------------------------------
$ 3,764 $ 2,280
=======================================================================================================================
82 Notes to the Consolidated Financial Statements
The Company has used the following estimated benchmark future prices
("escalated pricing") in its ceiling test prepared in accordance with Canadian
GAAP, as at December 31, 2005:
--------------------------------------------------------------------------------------------------------------------------------
Average
annual change
2006 2007 2008 2009 2010 thereafter
--------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs
North America
WTI at Cushing (US$/bbl) $ 60.81 $ 61.61 $ 54.60 $ 50.19 $ 47.76 1.5%
Hardisty Heavy 12(degree) API (C$/bbl) $ 37.07 $ 37.29 $ 34.23 $ 32.27 $ 31.15 1.6%
Edmonton Par (C$/bbl) $ 70.07 $ 70.99 $ 62.73 $ 57.53 $ 54.65 1.5%
North Sea and Offshore West Africa
North Sea Brent (US$/bbl) $ 58.81 $ 59.58 $ 52.54 $ 48.10 $ 45.64 1.5%
--------------------------------------------------------------------------------------------------------------------------------
Natural gas
North America
Henry Hub Louisiana (US$/mmbtu) $ 11.59 $ 10.11 $ 8.50 $ 7.58 $ 7.32 1.5%
AECO (C$/mmbtu) $ 11.58 $ 10.84 $ 8.95 $ 7.87 $ 7.57 1.5%
Huntingdon/Sumas (C$/mmbtu) $ 11.34 $ 10.70 $ 8.81 $ 7.73 $ 7.43 1.5%
================================================================================================================================
4. LONG-TERM DEBT
-------------------------------------------------------------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------------------------------------------------------------
Bank credit facilities
Bankers' acceptances $ 122 $ -
US dollar bankers' acceptances (2005 - US$nil, 2004 - US$471 million) - 557
Medium-term notes
7.40% unsecured debentures due March 1, 2007 125 125
4.95% unsecured debentures due June 1, 2015 400 -
Senior unsecured notes
7.69% due December 19, 2005 (2005 - US$nil, 2004 - US$125 million) - 194
Adjustable rate due May 27, 2009 (2005 - US$93 million, 2004 - US$93 million) 108 112
Preferred securities
8.30% due June 25,2011 (2005 - US$nil, 2004 - US$80 million) - 96
US dollar debt securities
6.70% due July 15, 2011 (2005 - US$400 million, 2004 - US$400 million) 467 482
5.45% due October 1, 2012 (2005 - US$350 million, 2004 - US$350 million) 408 421
4.90% due December 1, 2014 (2005 - US$350 million, 2004 - US$350 million) 408 421
7.20% due January 15, 2032 (2005 - US$400 million, 2004 - US$400 million) 467 482
6.45% due June 30, 2033 (2005 - US$350 million, 2004 - US$350 million) 408 421
5.85% due February 1, 2035 (2005 - US$350 million, 2004 - US$350 million) 408 421
-------------------------------------------------------------------------------------------------------------------------------
3,321 3,732
Less: current portion of long-term debt - 194
-------------------------------------------------------------------------------------------------------------------------------
$ 3,321 $ 3,538
===============================================================================================================================
BANK CREDIT FACILITIES
As at December 31, 2005 the Company had in place unsecured syndicated bank
credit facilities of $3,425 million, comprised of:
o a $100 million operating demand facility;
o a two-tranche revolving credit and term loan facility of $1,825
million; and
o a 5-year revolving and term loan facility of $1,500 million.
The first $1,000 million tranche of the $1,825 million facility is fully
revolving for a period of three years to June 2008. The second tranche of $825
million is fully revolving for a period of five years to June 2010. Both
tranches are extendible annually for one-year periods at the mutual agreement
of the Company and the lenders. If not extended, the full amount of the
outstanding principal would be repayable at the end of year two following the
initiation of the term period. The $1,500 million revolving credit and term
loan facility has a five-year term, with three, one-year extension provisions.
If the facility is not extended, the amount outstanding would be repayable in
December 2009. These facilities provide that the borrowings may be made by way
of operating advances, prime loans, bankers' acceptances, US base rate loans
or US dollar LIBOR advances, which bear interest at the bank's prime rates or
at money market rates plus applicable margins.
The weighted average interest rate of the bank credit facilities outstanding
at December 31, 2005, was 5.44% (2004 - 3.47%). The Company also has a
(pound)15 million demand overdraft credit facility related to the Company's
North Sea operations. At December 31, 2005 there were no amounts drawn on this
facility.
In addition to the outstanding debt, as at December 31, 2005 letters of credit
aggregating $24 million (2004 - $24 million) have been issued.
Notes to the Consolidated Financial Statements 83
MEDIUM-TERM NOTES
In May 2005, the Company issued $400 million of debt securities maturing June
2015, bearing interest at 4.95%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.
In May 2004, the Company repaid the $125 million 6.85% unsecured debentures
due May 2004, which were issued under a previous medium-term note program.
In January 2006, the Company issued $400 million of debt securities maturing
January 2013, bearing interest at 4.50%. Proceeds from the securities issued
were used to repay bankers' acceptances under the Company's bank credit
facilities. After issuing these securities, the Company has $1.6 billion
remaining on its $2 billion shelf prospectus filed in August 2005 that allows
for the issue of medium-term notes in Canada until September 2007. If issued,
these securities will bear interest as determined at the date of issuance.
SENIOR UNSECURED NOTES
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes. The 6.42% senior unsecured notes were repaid in May 2004.
The adjustable rate senior unsecured notes bear interest at 6.54% and have
annual principal repayments of US$31 million commencing in May 2007, through
May 2009.
PREFERRED SECURITIES
In September 2005, the Company redeemed the US$80 million 8.30% preferred
securities due May 25, 2011 for cash consideration of US$91 million, including
an early repayment premium of US$11 million as required under the Note
Purchase Program.
US DOLLAR DEBT SECURITIES
In June 2005, the Company filed a short form prospectus that allows for the
issue of up to US$2 billion of debt securities in the United States until July
2007. If issued, these securities will bear interest determined as at the date
of issuance.
In December 2004, the Company issued US$350 million of debt securities
maturing December 2014, bearing interest at 4.90% and US$350 million of debt
securities maturing February 2035, bearing interest at 5.85%. Proceeds from
the securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities. The Company has entered into certain
interest rate swap contracts to convert the fixed rate interest coupon into a
floating interest rate on the securities due December 2014 (note 10).
REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:
------------------------------------------------------------------------------
Year Repayment
------------------------------------------------------------------------------
2006 $ -
2007 $ 161
2008 $ 36
2009 $ 36
2010 $ -
Thereafter $ 2,966
==============================================================================
No debt repayments are reflected for the bank credit facilities due to the
extendable nature of the facilities.
5. OTHER LONG-TERM LIABILITIES
------------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------------
Asset retirement obligations $ 1,112 $ 1,119
Stock-based compensation 891 323
Risk management (note 10) 885 26
Other 17 -
------------------------------------------------------------------------------
2,905 1,468
Less: current portion 1,471 260
------------------------------------------------------------------------------
$ 1,434 $ 1,208
==============================================================================
84 Notes to the Consolidated Financial Statements
ASSET RETIREMENT OBLIGATIONS
At December 31, 2005, the Company's total estimated undiscounted costs to
settle its asset retirement obligations with respect to crude oil and natural
gas properties and facilities was approximately $3,325 million (2004 - $3,060
million). Payments to settle these asset retirement obligations will occur on
an ongoing basis over a period of approximately 60 years and have been
discounted using an average credit-adjusted risk-free interest rate of 6.8%. A
reconciliation of the discounted asset retirement obligations is as follows:
------------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------------
Asset retirement obligations
Balance - beginning of year $ 1,119 $ 897
Liabilities incurred 47 339
Liabilities settled (46) (32)
Asset retirement obligation accretion 69 51
Revision of estimates (56) (86)
Foreign exchange (21) (50)
------------------------------------------------------------------------------
Balance - end of year $ 1,112 $ 1,119
==============================================================================
The Company's pipelines have an indeterminant life and therefore the fair
values of the related asset retirement obligations cannot be reasonably
determined. The asset retirement obligations for these assets will be recorded
in the first year in which the lives of the assets are determinable.
STOCK-BASED COMPENSATION
The Company recognizes a liability for the potential cash settlements under
its Option Plan. The current portion represents the maximum amount of the
liability payable within the next 12-month period if all vested options are
surrendered for cash settlement.
------------------------------------------------------------------------------
2005 2004
------------------------------------------------------------------------------
Stock-based compensation
Balance - beginning of year $ 323 $ 171
Stock-based compensation provision 723 249
Cash payment for options surrendered (227) (80)
Transferred to common shares (29) (38)
Capitalized to Horizon Project 101 21
------------------------------------------------------------------------------
Balance - end of year 891 323
Less: current portion of stock-based compensation 629 243
------------------------------------------------------------------------------
$ 262 $ 80
==============================================================================
6. TAXES
TAXES OTHER THAN INCOME TAX
------------------------------------------------------------------------------
2005 2004 2003
------------------------------------------------------------------------------
Current petroleum revenue tax $ 181 $ 190 $ 106
Deferred petroleum revenue tax recovery (9) (45) (9)
Provincial capital taxes and surcharges 22 20 10
------------------------------------------------------------------------------
$ 194 $ 165 $ 107
==============================================================================
INCOME TAX
The provision for income tax is as follows:
------------------------------------------------------------------------------
2005 2004 2003
------------------------------------------------------------------------------
Current income tax expense
Current income tax - North America $ 82 $ 89 $ 43
Large Corporations Tax - North America 16 11 16
Current income tax - North Sea 155 2 23
Current income tax - Offshore West Africa 32 13 10
Current income tax - other 1 1 -
------------------------------------------------------------------------------
286 116 92
Future income tax expense 353 474 338
------------------------------------------------------------------------------
Income tax $ 639 $ 590 $ 430
==============================================================================
Notes to the Consolidated Financial Statements 85
The provision for income tax is different from the amount computed by applying
the combined statutory Canadian federal and provincial income tax rates to
earnings before taxes. The reasons for the difference are as follows:
2005 2004 2003
--------------------------------------------------------------------------------------------------------
Canadian statutory income tax rate 38.0% 39.3% 41.1%
--------------------------------------------------------------------------------------------------------
Income tax provision at statutory rate $ 716 $ 849 $ 797
Effect on income taxes of:
Non-deductible portion of Canadian crown payments 309 221 285
Canadian resource allowance (293) (270) (281)
Large Corporations Tax 16 11 16
Deductible UK petroleum revenue tax (65) (57) (40)
Foreign tax rate differentials (1) (31) 20
Federal income tax rate reductions - - (247)
Provincial income tax rate reductions (19) (66) (31)
Non-taxable portion of foreign exchange (15) (36) (103)
Attributed Canadian Royalty Income (21) (4) 4
Other 12 (27) 10
--------------------------------------------------------------------------------------------------------
Income tax $ 639 $ 590 $ 430
========================================================================================================
The following table summarizes the temporary differences that give rise to the
net future income tax asset and liability:
--------------------------------------------------------------------------------------------------------
2005 2004
--------------------------------------------------------------------------------------------------------
Future income tax liabilities
Property, plant and equipment $ 3,960 $ 3,677
Timing of partnership items 1,646 1,254
Unrealized foreign exchange gain on long-term debt 112 102
Risk management activities - 19
Other 31 43
Future income tax assets
Asset retirement obligations (384) (418)
Capital loss carryforwards (79) (92)
Attributed Canadian Royalty Income (75) (54)
Stock-based compensation (300) (106)
Risk management activities (304) -
Deferred petroleum revenue tax (59) (58)
--------------------------------------------------------------------------------------------------------
Future income tax liability 4,548 4,367
Less: future income tax asset (487) (83)
--------------------------------------------------------------------------------------------------------
Net future income tax liability $ 5,035 $ 4,450
========================================================================================================
A significant portion of North America's taxable income is generated by
partnerships. Income taxes are incurred on the partnerships' taxable income in
the year following their inclusion in the Company's consolidated net earnings.
Current income tax will vary and is dependent upon the nature and amount of
capital expenditures incurred in Canada.
During 2005, the Government of British Columbia enacted legislation to reduce
its corporate income tax rate by 1.5%, effective July 1, 2005, resulting in a
$19 million reduction in the Company's future income tax liability.
During 2004, the Government of Alberta enacted legislation to reduce its
corporate income tax rate by 1.0% effective April 1, 2004, resulting in a $66
million reduction in the Company's future income tax liability.
During 2003, the Government of Alberta enacted legislation to reduce its
corporate income tax rate by 0.5% effective April 1, 2003. Also during 2003,
the Canadian federal government enacted legislation to change the taxation of
resource income. The legislation reduces the corporate income tax rate on
resource income from 28% to 21% over five years beginning January 1, 2003.
Over the same period, the deduction for resource allowance is being phased out
and a deduction for actual crown royalties paid is being phased in. The
Company's future income tax liability was reduced by $31 million with respect
to the Alberta corporate income tax rate reduction and by $247 million with
respect to the federal resource income tax rate changes.
86 Notes to the Consolidated Financial Statements
7. SHARE CAPITAL
AUTHORIZED
200,000 Class 1 preferred shares with a stated value of $10.00 each.
Unlimited number of common shares without par value.
ISSUED
2005 2004
-------------------------------------------------------------------------------------------------------------------------
Numbers of Numbers of
shares shares
Common shares (thousands) Amount (thousands) Amount
-------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 536,361 $ 2,408 534,926 $ 2,353
Issued upon exercise of stock options 837 9 3,182 24
Previously recognized liability on stock options
exercised for common shares - 29 - 38
Purchase of common shares under Normal Course Issuer Bid (850) (4) (1,747) (7)
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year 536,348 $ 2,442 536,361 $ 2,408
=========================================================================================================================
SHARE SPLIT
The Company's shareholders approved a subdivision or share split of its issued
and outstanding common shares on a two-for-one basis at the Company's Annual
and Special Meeting held on May 5, 2005. All common share and per common share
amounts have been restated to retroactively reflect the share split.
NORMAL COURSE ISSUER BID
In January 2005, the Company announced the renewal of its Normal Course Issuer
Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange to purchase up to 26,818,012 common shares or 5% of the
outstanding common shares of the Company on the date of announcement, during
the 12-month period beginning January 24, 2005 and ending January 23, 2006. As
at December 31, 2005, the Company had purchased 850,000 common shares (2004 -
1,746,800 common shares) at an average price of $53.29 per common share (2004
- $19.00 per common share), for a total cost of $45 million (2004 - $33
million). Retained earnings was reduced by $41 million (2004 - $26 million),
representing the excess of the purchase price of the common shares over their
stated value.
On January 20, 2006, the Company announced the renewal of its Normal Course
Issuer Bid through the facilities of the Toronto Stock Exchange and the New
York Stock Exchange to purchase up to 26,852,545 common shares or 5% of the
outstanding common shares of the Company on the date of the announcement,
during the 12-month period beginning January 24, 2006 and ending January
23,2007. As at February 21, 2006, the Company had not purchased any additional
shares under the Normal Course Issuer Bid.
DIVIDEND POLICY
The Company pays regular quarterly dividends in January, April, July and
October of each year.
On February 21, 2006, the Board of Directors set the Company's regular
quarterly dividend at $0.075 per common share (2005 - $0.059 per common share,
2004 - $0.050 per common share).
STOCK OPTIONS
The Option Plan provides for granting of stock options to employees. Stock
options granted under the Option Plan have a maximum term of six years to
expiry and vest equally over a five-year period. The exercise price of each
stock option granted is determined at the closing market price of the common
shares on the Toronto Stock Exchange on the day prior to the grant. Each stock
option granted permits the holder to purchase one common share of the Company
at the stated exercise price.
In June 2003 the Company approved a modification to its Option Plan providing
the stock option holder the right to elect to receive a cash payment equal to
the difference between the exercise price of the stock option and the market
price of the Company's common shares on the date of surrender, multiplied by
the number of common shares covered by the stock options surrendered, in lieu
of receiving common shares. The modification to the Option Plan was accounted
for prospectively.
Notes to the Consolidated Financial Statements 87
For the year ended December 31, 2005, the Company recorded stock-based
compensation expense of $723 million (2004 - $249 million, 2003 - $200
million). In 2005, $101 million was capitalized to the Horizon Project (2004 -
$21 million, 2003 - $10 million). As at December 31, 2005, the total liability
for expected cash settlements under the Option Plan was $891 million (2004 -
$323 million), of which $629 million (2004 - $243 million) was included as a
current liability. During the year ended December 31, 2005, cash payments of
$227 million were made for 7,523,000 stock options surrendered (2004 - cash
payments of $80 million for 7,562,000 stock options surrendered). The
following table summarizes information relating to stock options outstanding
at December 31, 2005 and 2004:
2005 2004
-------------------------------------------------------------------------------------------------------------------------
Weighted Weighted
Stock average Stock average
options exercise options exercise
(thousands) price (thousands) price
=========================================================================================================================
Outstanding - beginning of year 32,522 $ 12.37 35,578 $ 9.86
Granted 7,959 $ 32.51 9,722 $ 17.95
Exercised for common shares (837) $ 9.81 (3,182) $ 7.55
Surrendered for cash settlement (7,523) $ 10.49 (7,562) $ 9.36
Forfeited (1,611) $ 19.36 (2,034) $ 13.86
-------------------------------------------------------------------------------------------------------------------------
Outstanding - end of year 30,510 $ 17.79 32,522 $ 12.37
-------------------------------------------------------------------------------------------------------------------------
Exercisable - end of year 8,677 $ 11.21 7,632 $ 9.92
=========================================================================================================================
The range of exercise prices of stock options outstanding and exercisable at
December 31, 2005 was as follows:
Stock options outstanding Stock options exercisable
-------------------------------------------------------------------------------------------------------------------------
Weighted
Stock average Weighted Stock Weighted
options remaining average options average
outstanding term exercise exercisable exercise
Range of exercise prices (thousands) (years) price (thousands) price
-------------------------------------------------------------------------------------------------------------------------
$ 7.85 - $ 9.99 8,794 1.41 $ 9.63 4,835 $ 9.54
$10.00 - $14.99 6,690 2.50 $ 11.74 2,780 $ 11.54
$15.00 - $19.99 6,234 3.53 $ 17.07 883 $ 17.05
$20.00 - $24.99 1,568 4.82 $ 22.89 176 $ 22.55
$25.00 - $29.99 4,301 4.18 $ 26.26 3 $ 26.26
$30.00 - $34.99 1,449 4.84 $ 33.22 - $ -
$40.00 - $44.99 201 5.45 $ 40.25 - $ -
$45.00 - $49.99 251 5.54 $ 47.16 - $ -
$50.00 - $54.99 600 5.72 $ 54.43 - $ -
$55.00 - $59.35 422 5.88 $ 55.89 - $ -
-------------------------------------------------------------------------------------------------------------------------
30,510 3.02 $ 17.79 8,677 $ 11.21
=========================================================================================================================
8. FOREIGN CURRENCY TRANSLATION ADJUSTMENT
The foreign currency translation adjustment represents the unrealized gain
(loss) on the Company's net investment in self-sustaining foreign operations.
Effective July 1, 2002, the Company designated certain US dollar denominated
debt as a hedge against its net investment in US dollar-based self-sustaining
foreign operations. Accordingly, translation gains and losses on this US
dollar denominated debt are included in the foreign currency translation
adjustment.
-------------------------------------------------------------------------------------------------------------------------
2005 2004
-------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year $ (6) $ 3
Unrealized loss on translation of net investment (12) (24)
Hedge of net investment with US dollar denominated debt, net of tax 9 15
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year $ (9) $ (6)
=========================================================================================================================
88 Notes to the Consolidated Financial Statements
9. NET EARNINGS PER COMMON SHARE
The following table provides a reconciliation between basic and diluted
amounts per common share:
---------------------------------------------------------------------------------------------------------------------------
2005 2004(2) 2003(2)
---------------------------------------------------------------------------------------------------------------------------
(thousands of shares)
Weighted average common shares outstanding - basic 536,650 536,223 536,940
Effect of dilutive stock options (1) - - 4,889
Assumed settlement of preferred securities with common shares 1,775 4,461 7,816
---------------------------------------------------------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 538,425 540,684 549,645
---------------------------------------------------------------------------------------------------------------------------
Net earnings $ 1,050 $ 1,405 $ 1,403
Interest on preferred securities, net of tax 4 5 5
Revaluation of preferred securities, net of tax (2) (4) (18)
---------------------------------------------------------------------------------------------------------------------------
Diluted net earnings $ 1,052 $ 1,406 $ 1,390
---------------------------------------------------------------------------------------------------------------------------
Net earnings per common share
Basic $ 1.96 $ 2.62 $ 2.62
Diluted $ 1.95 $ 2.60 $ 2.53
===========================================================================================================================
(1) The Option Plan described in note 7 results in a liability and expense
for all outstanding stock options. As such, the potential common shares
associated with the stock options are not included in diluted earnings
per share effective from June 2003, the date of the modification.
(2) Restated to reflect two-for-one share split in May 2005.
10. FINANCIAL INSTRUMENTS
RISK MANAGEMENT
On January 1, 2004, the fair values of all outstanding derivative financial
instruments that were not designated as hedges for accounting purposes were
recorded on the consolidated balance sheet, with an offsetting net deferred
revenue amount. Subsequent net changes in the fair value of non-designated
financial instruments have been recognized on the consolidated balance sheet
and in net earnings. The estimated fair value for all derivative financial
instruments is based on third party indications.
As at December 31, 2005 and 2004, the estimated fair values of non-designated
financial derivatives were comprised as follows:
2005 2004
-------------------------------------------------------------------------------------------------------------------------
Risk Risk
management Deferred management Deferred
mark-to-market revenue mark-to-market revenue
-------------------------------------------------------------------------------------------------------------------------
Balance - beginning of year $ 66 $ (26) $ 40 $ (40)
Net cost of put options outstanding as at December 31 190 - 38 -
Net change in fair value of financial instruments
outstanding as at December 31 (943) - 26 -
Amortization of deferred revenue - 18 - 14
-------------------------------------------------------------------------------------------------------------------------
Balance - end of year (687) (8) 104 (26)
Less: put premium financing obligations (190) - (38) -
-------------------------------------------------------------------------------------------------------------------------
(877) (8) 66 (26)
Less: current portion (1) 834 8 34 17
-------------------------------------------------------------------------------------------------------------------------
$ (43) $ - $ 32 $ (9)
=========================================================================================================================
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective option.
Net losses (gains) from risk management activities for the years ended
December 31 were as follows:
-------------------------------------------------------------------------------------------------------------------------
2005 2004 2003
-------------------------------------------------------------------------------------------------------------------------
Net realized risk management loss $ 1,027 $ 474 $ 148
Net unrealized risk management loss (gain) 925 (40) -
-------------------------------------------------------------------------------------------------------------------------
$ 1,952 $ 434 $ 148
=========================================================================================================================
As at December 31, 2005, the net unrecognized liability related to the
estimated fair values of derivative financial instruments designated as hedges
was $990 million (December 31, 2004 - net unrecognized asset of $33 million).
Notes to the Consolidated Financial Statements 89
FINANCIAL CONTRACTS
The Company's financial instruments recognized in the consolidated balance
sheets consist of cash, accounts receivable, accounts payable, accrued
liabilities, risk management activities, stock-based compensation and
long-term debt.
The estimated fair values of financial instruments have been determined based
on the Company's assessment of available market information, appropriate
valuation methodologies and third party indications. However, these estimates
may not necessarily be indicative of the amounts that could be realized or
settled in a current market transaction.
The carrying value of cash, accounts receivable, accounts payable, accrued
liabilities, stock-based compensation and long-term debt with variable
interest rates approximate their fair value.
The estimated fair values of other financial instruments were as follows:
2005 2004
-----------------------------------------------------------------------------------------------------------
Carrying Value Fair Value Carrying Value Fair Value
-----------------------------------------------------------------------------------------------------------
Asset (liability)
Derivative financial instruments $ (687) $ (1,700) $ 66 $ 33
Fixed rate notes $ (3,199) $ ( 3,367) $ (3,175) $ (3,364)
============================================================================================================
COMMODITY PRICE RISK MANAGEMENT
The Company uses certain derivative financial instruments to manage its
commodity price exposures. These financial instruments are entered into solely
for hedging purposes and are not used for trading or other speculative
purposes. The following summarizes transactions outstanding as at December 31,
2005:
-------------------------------------------------------------------------------------------------------------------------
Remaining term Volume Average price Index
-------------------------------------------------------------------------------------------------------------------------
Crude oil
Crude oil price collars Jan 2006 - Dec 2006 167,644 bbl/d US$38.26 - US$48.28 WTI
Jan 2006 - Dec 2006 82,356 bbl/d US$44.75 - US$76.93 WTI
Jan 2006 - Dec 2006 22,000 bbl/d C$46.53 - C$58.67 WTI
Crude oil puts (1) Mar 2006 - Jul 2006 55,000 bbl/d US$40.00 WTI
Aug 2006 - Dec 2006 51,000 bbl/d US$45.00 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$28.00 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Brent differential swaps Jan 2006 - Dec 2006 25,000 bbl/d US$1.29 WTI/Dated Brent
Jan 2007 - Dec 2007 50,000 bbl/d US$1.34 WTI/Dated Brent
=========================================================================================================================
(1) Subsequent to year end, the Company settled 17,000 bbl/d of the US$40.00
put options for 2006 and purchased 100,000 bbl/d of US$50.00 put options
for 2007.
-------------------------------------------------------------------------------------------------------------------------
Remaining term Volume Average price Index
-------------------------------------------------------------------------------------------------------------------------
Natural gas
AECO collars Jan 2006 - Mar 2006 700,0OO GJ/d C$5.88 - C$8.78 AECO
Jan 2006 - Mar 2006 400,000 GJ/d C$6.00 - C$12.29 AECO
Jan 2006 - Mar 2006 100,000 GJ/d C$8.00 - C$27.75 AECO
Apr 2006 - Jun 2006 993,000 GJ/d C$5.71 - C$8.13 AECO
Apr 2006 - Jun 2006 100,000 GJ/d C$7.00 - C$14.16 AECO
Jul 2006 - Sep 2006 725,000 GJ/d C$5.60 - C$7.59 AECO
Jul 2006 - Sep 2006 100,000 GJ/d C$7.00 - C$14.16 AECO
Oct 2006 - Dec 2006 244,000 GJ/d C$5.60 - C$7.59 AECO
Oct 2006 - Dec 2006 100,000 GJ/d C$7.00 - C$14.16 AECO
Oct 2006 - Dec 2006 464,000 GJ/d C$7.50 - C$18.80 AECO
Jan 2007 - Mar 2007 700,000 GJ/d C$7.50 - C$18.80 AECO
=========================================================================================================================
Commodity related derivative financial instruments designated as hedges at
December 31, 2005, were all classified as cash flow hedges.
90 Notes to the Consolidated Financial Statements
INTEREST RATE / RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term
debt and to interest rate cash flow-risk on its floating rate long-term debt.
The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31, 2005, the
Company had the following interest rate swap contracts outstanding:
-------------------------------------------------------------------------------------------------------------------------
Remaining term Amount ($ millions) Fixed rate Floating rate
------------------------------------------------------------------------------------------------------------------------
Interest rate
Swaps - fixed to floating Jan 2006 - Jan 2007 US$200 (2) 7.20% LIBOR (1) + 2.23%
Jan 2006 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jan 2006 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps - floating to fixed Jan 2006 - Mar 2007 C$6 7.36% CDOR (3)
========================================================================================================================
(1) London Interbank Offered Rate
(2) Subsequent to year end the Company received approximately $1 million in
settlement of the 7.20% fixed to floating rate swap.
(3) Canadian Deposit Overnight Rate
Interest rate related derivative financial instruments designated as hedges at
December 31, 2005, were all classified as fair value hedges.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign exchange rate risk in Canada on its US
dollar denominated debt and on product sales based on US dollar denominated
benchmarks. The Company is also exposed to foreign exchange rate risk on
transactions conducted in foreign currencies in its foreign subsidiaries and
in the carrying value of its self sustaining foreign subsidiaries. Cross
currency swap agreements are periodically used to manage currency exposure on
US dollar denominated long-term debt. The cross currency swap contracts
require the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. The Company may
also enter into foreign currency denominated financial instruments to manage
future US dollar denominated crude oil and natural gas sales. The Company has
designated certain US dollar denominated debt as a hedge against its net
investment in US dollar-based self-sustaining foreign operations (note 8).
COUNTERPARTY CREDIT RISK MANAGEMENT
Accounts receivable are mainly with customers in the crude oil and natural gas
industry and are subject to normal industry credit risks. The Company manages
this risk by entering into sales contracts with only highly rated entities. In
addition, the Company reviews its exposure to individual companies on a
regular basis and where appropriate, ensures that parental guarantees or
letters of credit are in place to minimize the impact in the event of default.
The Company is also exposed to possible losses in the event of non-performance
by counterparties to derivative financial instruments; however, the Company
manages this credit risk by entering into agreements with only highly rated
financial institutions and other entities.
11. COMMITMENTS
The Company has committed to certain payments as follows:
-----------------------------------------------------------------------------------------------------------------
2006 2007 2008 2009 2010 Thereafter
-----------------------------------------------------------------------------------------------------------------
Product transportation and pipeline (1) $ 195 $ 133 $ 148 $ 94 $ 85 $ 1,111
Offshore equipment operating lease $ 51 $ 51 $ 52 $ 51 $ 51 $ 180
Offshore drilling $ 132 $ 100 $ 35 $ -- $ -- $ --
Asset retirement obligations (2) $ 82 $ 4 $ 4 $ 4 $ 7 $ 3,224
Other (3) $ 61 $ 62 $ 21 $ 29 $ 23 $ 8
=================================================================================================================
(1) During the year, the Company entered into a 25 year pipeline
transportation agreement commencing in 2008, related to future crude oil
production. The agreement is renewable for successive 10-year periods at
the Company's option. During the initial term, annual toll payments before
operating costs will be approximately $35 million.
(2) Represents management's estimate of the future undiscounted payments to
settle asset retirement obligations related to resource properties,
facilities, production platform and pipelines, based on current
legislation and industry operating practices.
(3) Consists of future expenditures related primarily to office lease,
electricity and crude oil processing.
The Board of Directors has approved the construction costs for Phase 1 of the
Horizon Project, which are budgeted to be $6.8 billion, including a
contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6
billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and
2008.
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect
on its consolidated financial position.
Notes to the Consolidated Financial Statements 91
12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Changes in non-cash working capital were as follows:
----------------------------------------------------------------------------------------------------
2005 2004 2003
----------------------------------------------------------------------------------------------------
Decrease (increase) in non-cash working capital
Accounts receivable and other $ (498) $ (329) $ 35
Accounts payable 196 39 125
Accrued liabilities 716 194 122
----------------------------------------------------------------------------------------------------
Net change in non-cash working capital $ 414 $ (96) $ 282
----------------------------------------------------------------------------------------------------
Relating to:
Operating activities $ (147) $ (14) $ (48)
Financing activities 19 6 (11)
Investing activities 542 (88) 341
----------------------------------------------------------------------------------------------------
$ 414 $ (96) $ 282
----------------------------------------------------------------------------------------------------
Other cash flow information:
----------------------------------------------------------------------------------------------------
Interest paid $ 200 $ 192 $ 178
Taxes paid $ 430 $ 218 $ 51
====================================================================================================
13. SEGMENTED INFORMATION
The Company's crude oil and natural gas activities are conducted in three
geographic segments: North America, North Sea and Offshore West Africa. These
activities relate to the exploration, development, production and marketing of
crude oil, natural gas liquids and natural gas.
The Company's Horizon Project has been classified as a separate segment. As
the bitumen will be recovered through mining operations, this project
constitutes a distinct segment from crude oil and natural gas activities.
There are currently no revenues for this project and all directly related
expenditures have been capitalized.
Midstream activities include the Company's pipeline operations and an
electricity co-generation system.
Activities that are not included in the above segments are included in the
segmented information as other.
Inter-segment eliminations include internal transportation and electricity
charges.
Crude oil and natural gas
---------------------------------------------------------------------------------------------------------------
North America North Sea Offshore West Africa
2005 2004 2003 2005 2004 2003 2005 2004 2003
---------------------------------------------------------------------------------------------------------------
Segmented revenue $ 7,932 $ 5,979 $ 5,021 $ 1,659 $ 1,317 $ 953 $ 485 $ 222 $ 155
Less: royalties (1,350) (1,003) (868) (3) (2) 1 (13) (6) (5)
---------------------------------------------------------------------------------------------------------------
Revenue, net of
royalties 6,582 4,976 4,153 1,656 1,315 954 472 216 150
---------------------------------------------------------------------------------------------------------------
Segmented expenses
Production 1,211 976 845 379 370 314 53 36 38
Transportation 287 256 264 20 32 30 -- -- --
Depletion, depreciation
and amortization 1,595 1,444 1,209 306 265 252 104 53 41
Asset retirement
obligation accretion 34 28 26 34 22 36 1 1 --
Realized risk
management activities 870 362 157 157 112 (9) -- -- --
---------------------------------------------------------------------------------------------------------------
Total segmented
expenses 3,997 3,066 2,501 896 801 623 158 90 79
---------------------------------------------------------------------------------------------------------------
Segmented earnings
before the
following $ 2,585 $ 1,910 $ 1,652 $ 760 $ 514 $ 331 $ 314 $ 126 $ 71
---------------------------------------------------------------------------------------------------------------
Non-segmented expenses
Administration
Stock-based
compensation
Interest
Unrealized risk
management activities
Foreign exchange gain
Total non-segmented
expenses
Earnings before taxes
Taxes other than
income tax
Current income tax
expense
Future income tax
expense
Net earnings
92 Notes to the Consolidated Financial Statements
Inter-segment
Midstream elimination and other Total
----------------------------------------------------------------------------------------------------------------
2005 2004 2003 2005 2004 2003 2005 2004 2003
----------------------------------------------------------------------------------------------------------------
Segmented revenue $ 77 $ 68 $ 61 $ (46) $ (39) $ (35) $10,107 $ 7,547 $ 6,155
Less: royalties -- -- -- -- -- -- (1,366) (1,011) (872)
----------------------------------------------------------------------------------------------------------------
Revenue, net of
royalties 77 68 61 (46) (39) (35) 8,741 6,536 5,283
----------------------------------------------------------------------------------------------------------------
Segmented expenses
Production 24 20 15 (4) (2) (3) 1,663 1,400 1,209
Transportation -- -- -- (37) (38) (32) 270 250 262
Depletion, depreciation
and amortization 8 7 7 -- -- -- 2,013 1,769 1,509
Asset retirement
obligation accretion -- -- -- -- -- -- 69 51 62
Realized risk
management activities -- -- -- -- -- -- 1,027 474 148
----------------------------------------------------------------------------------------------------------------
Total segmented
expenses 32 27 22 (41) (40) (35) 5,042 3,944 3,190
----------------------------------------------------------------------------------------------------------------
Segmented earnings
before the
following $ 45 $ 41 $ 39 $ (5) $ 1 $ -- $ 3,699 $ 2,592 $ 2,093
--------------------------------------------------------------------------------------
Non-segmented expenses
Administration 151 125 87
Stock-based
compensation 723 249 200
Interest 149 189 201
Unrealized risk
management activities 925 (40) --
Foreign exchange gain (132) (91) (335)
--------------------------
Total non-segmented
expenses 1,816 432 153
--------------------------
Earnings before taxes 1,883 2,160 1,940
Taxes other than
income tax 194 165 107
Current income tax
expense 286 116 92
Future income tax
expense 353 474 338
--------------------------
Net earnings $ 1,050 $ 1,405 $ 1,403
==========================
Notes to the Consolidated Financial Statements 93
CAPITAL EXPENDITURES
2005 2004
--------------------------------------------------------------------------------------------------------------------------------
Non-cash and Non-cash and
Cash fair value Capitalized Cash fair value Capitalized
expenditures adjustments(1) costs expenditures adjustments(1) costs
--------------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 2,530 $ (22) $ 2,508 $ 3,329 $ 508 $ 3,837
North Sea 387 (136) 251 608 172 780
Offshore West Africa 439 27 466 295 -- 295
Other 5 -- 5 1 -- 1
--------------------------------------------------------------------------------------------------------------------------------
3,361 (131) 3,230 4,233 680 4,913
Horizon Project 1,499 -- 1,499 291 -- 291
Midstream 4 -- 4 16 -- 16
Head office 22 -- 22 35 -- 35
--------------------------------------------------------------------------------------------------------------------------------
$ 4,886 $ (131) $ 4,755 $ 4,575 $ 680 $ 5,255
================================================================================================================================
(1) Asset retirement obligations, future income tax adjustments on non-tax
base assets, and other fair value adjustments.
------------------------------------------------------------------------------------------------------------------------
Segmented property, plant and equipment, net 2005 2004
------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 14,310 $ 13,394
North Sea 1,681 1,823
Offshore West Africa 1,253 901
Other 13 8
Horizon Project 2,169 672
Midstream 203 209
Head office 65 57
------------------------------------------------------------------------------------------------------------------------
$ 19,694 $ 17,064
========================================================================================================================
Segmented assets 2005 2004
------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 15,939 $ 14,390
North Sea 1,950 2,036
Offshore West Africa 1,371 914
Other 30 35
Horizon Project 2,239 672
Midstream 258 268
Head office 65 57
------------------------------------------------------------------------------------------------------------------------
$ 21,852 $ 18,372
========================================================================================================================
14. BUSINESS COMBINATIONS
PETROVERA PARTNERSHIP
In February 2004, the Company acquired certain resource properties in its
Northern Plains core region, collectively known as the Petrovera Partnership
("Petrovera"), for $471 million.
The acquisition was accounted for based on the purchase method. Results from
Petrovera are consolidated with the results of the Company effective from the
date of acquisition. The allocation of the purchase price to assets acquired
and liabilities assumed based on their fair values was as follows:
------------------------------------------------------------------------------
FEBRUARY 1, 2004
------------------------------------------------------------------------------
Purchase price:
Cash consideration $ 467
Cash acquired (23)
Non-cash working capital deficit assumed 27
------------------------------------------------------------------------------
Total purchase price $ 471
==============================================================================
Purchase price allocated as follows:
Property, plant and equipment $ 643
Future income tax liability (129)
Asset retirement obligation (43)
------------------------------------------------------------------------------
$ 471
==============================================================================
94 Notes to the Consolidated Financial Statements
15. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The Company's consolidated financial statements have been prepared in
accordance with generally accepted accounting principles in Canada ("Canadian
GAAP"). These principles conform in all material respects with those in the
United States ("US GAAP") except for those noted below. Differences arising
from US GAAP disclosure requirements are not addressed.
The application of US GAAP would have the following effects on consolidated
net earnings as reported:
-----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars, except per common share amounts) Notes 2005 2004 2003
-----------------------------------------------------------------------------------------------------------------------
Net earnings - Canadian GAAP $ 1,050 $ 1,405 $ 1,403
Adjustments
Depletion, net of tax of $3 million (2004 - $2 million; 2003
- $3 million) (A) 4 4 4
Derivative financial instruments and hedging activities,
net of tax of $11 million (2004 - $7 million; 2003 - $20
million) (B) (19) (9) (49)
Capitalized interest, net of tax of $11 million (C) -- 16 --
Cumulative effect of change in accounting policy, net of tax
of $3 million (D) -- -- (4)
-----------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP $ 1,035 $ 1,416 $ 1,354
-----------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP per common share
Basic $ 1.93 $ 2.64 $ 2.52
Diluted $ 1.93 $ 2.62 $ 2.44
=======================================================================================================================
Comprehensive income under US GAAP would be as follows:
-----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars) Notes 2005 2004 2003
-----------------------------------------------------------------------------------------------------------------------
Net earnings - US GAAP $ 1,035 $ 1,416 $ 1,354
Derivative financial instruments and hedging activities,
net of tax of $312 million (2004 - $3 million; 2003 - $9
million) (B) (635) 8 20
Foreign currency translation adjustment (E) (3) (9) (23)
-----------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 397 $ 1,415 $ 1,351
=======================================================================================================================
The application of US GAAP would have the following effects on the
consolidated balance sheets as reported:
2005
-----------------------------------------
Canadian Increase US
(millions of Canadian dollars) Notes GAAP (decrease) GAAP
-----------------------------------------------------------------------------------------------------------------------
Current assets (B) $ 2,051 $ 338 $ 2,389
Property, plant and equipment (A,C) 19,694 (20) 19,674
Other long-term assets 107 -- 107
-----------------------------------------------------------------------------------------------------------------------
$ 21,852 $ 318 $ 22,170
-----------------------------------------------------------------------------------------------------------------------
Current liabilities (B) $ 3,825 $ 1,005 $ 4,830
Long-term debt (B) 3,321 (18) 3,303
Other long-term liabilities (B) 1,434 8 1,442
Future income tax (A,B,C) 5,035 (5) 5,030
Shareholders' equity (B,E) 8,237 (672) 7,565
-----------------------------------------------------------------------------------------------------------------------
$ 21,852 $ 318 $ 22,170
=======================================================================================================================
2004
-----------------------------------------
Canadian Increase US
(millions of Canadian dollars) Notes GAAP (decrease) GAAP
-----------------------------------------------------------------------------------------------------------------------
Current assets (B) $ 1,200 $ (33) $ 1,167
Property, plant and equipment (A,C) 17,064 (27) 17,037
Other long-term assets 108 -- 108
-----------------------------------------------------------------------------------------------------------------------
$ 18,372 $ (60) $ 18,312
-----------------------------------------------------------------------------------------------------------------------
Current liabilities (B) $ 1,852 $ (44) $ 1,808
Long-term debt 3,538 -- 3,538
Other long-term liabilities 1,208 -- 1,208
Future income tax (A,B,C) 4,450 6 4,456
Shareholders' equity (B,E) 7,324 (22) 7,302
-----------------------------------------------------------------------------------------------------------------------
$ 18,372 $ (60) $ 18,312
=======================================================================================================================
Notes to the Consolidated Financial Statements 95
NOTES:
(A) Under Canadian full cost accounting rules, costs capitalized in each cost
centre, net of future income taxes, are limited to an amount equal to the
undiscounted, future net revenues from proved reserves using estimated
future prices and costs, plus the carrying amount of unproved properties
and major development projects (the "ceiling test"). Under the full cost
method of accounting as set forth by the US Securities and Exchange
Commission, the ceiling test differs from Canadian GAAP in that future
net revenues from proved reserves are based on prices and costs as at the
balance sheet date ("constant dollar pricing") and are discounted at 10%.
(B) The Company accounts for its derivative financial instruments under
Canadian GAAP as described in note 1(P). For US GAAP purposes, Financial
Accounting Standards Board Statement ("FAS") 133, "Accounting for
Derivative Financial Instruments and Hedging Activities," as amended by
FAS 138 and FAS 149, establishes US GAAP accounting and reporting
standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities.
Generally, all derivatives, whether designated in hedging relationships
or not, and excluding normal purchases and normal sales, are required to
be recorded on the balance sheet at fair value. If the derivative is
designated as a fair value hedge, changes in the fair value of the
derivative and changes in the fair value of the hedged item attributable
to the hedged risk are recognized in the consolidated statements of
earnings each period. If the derivative is designated as a cash flow
hedge, the effective portions of the changes in fair value of the
derivative are initially recorded in other comprehensive income ("OCI")
each period and are recognized in the consolidated statements of earnings
when the hedged item is recognized. Therefore, ineffective portions of
changes in the fair value of hedging instruments are recognized in net
earnings immediately for both fair value and cash flow hedges.
The determination of hedge effectiveness and the measurement of hedge
ineffectiveness of cash flow hedges is based on a combination of third
party indications and internally derived valuations. The Company uses
these valuations to estimate the fair values of the underlying physical
commodity contracts.
(C) Under Canadian GAAP, the Company began capitalizing interest on the
Horizon Project when the Board of Directors approval was received in
2005. For US GAAP, capitalization of interest on projects constructed
over time is mandatory and interest has been capitalized to the costs of
construction beginning in 2004.
(D) Under Canadian GAAP, when the asset retirement obligation standard was
adopted prior period comparative balances were restated to reflect the
effect of the new standard on that year. Under US GAAP, when the asset
retirement obligation standard was adopted the cumulative effect of the
new standard on prior periods was included in earnings in the year
adopted.
(E) Under US GAAP, exchange gains and losses arising from the translation of
self-sustaining foreign operations are included in comprehensive income.
(F) Recently issued accounting standards under US GAAP:
SHARE-BASED PAYMENT
In December 2004, the Financial Accounting Standards Board ("FASB") issued FAS
123(R) "Share-Based Payment," which is a revision of FAS 123. This standard
requires all companies to reflect stock based compensation in their statement
of earnings for US GAAP. The fair value of stock options must be recognized at
the date of grant using option pricing models. The fair value must be
remeasured each quarter and changes in fair value must flow through the
statement of earnings. This is a difference from Canadian GAAP, where the
Company's options are valued at the difference between the exercise price and
the stock price. This standard is effective for the first interim or annual
reporting period of a registrant's first fiscal year beginning on or after
June 15, 2005. The Company plans to adopt this standard January 1, 2006.
ACCOUNTING CHANGES AND ERROR CORRECTIONS
In May 2005, the FASB issued FAS 154 "Accounting Changes and Error
Corrections," which replaces FAS 3 "Reporting Accounting Changes in Interim
Financial Statements" and APB Opinion 20 "Accounting Changes." The previous
standards required that changes in accounting principle be recognized by
including in net income of the period of the change the cumulative effect of
changing to the new accounting principle. The new standard requires that
accounting changes be applied retrospectively and that prior accounting
periods be restated as if the accounting principle had always been used. This
change eliminates a difference from Canadian GAAP. The new standard will be
applied to all future US GAAP accounting policy changes.
96 Notes to the Consolidated Financial Statements
MANAGEMENT'S DISCUSSION & ANALYSIS
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference for Canadian Natural Resources Limited (the "Company") may
constitute "forward-looking statements" within the meaning of the United
States Private Securities 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 "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: general economic and business
conditions which will, among other things, impact demand for and market prices
of the Company's products; foreign currency exchange rates; economic
conditions in the countries and regions in which the Company conducts
business; political uncertainty, including actions of or against terrorists or
insurgent groups or other conflict including conflict between states; industry
capacity; ability of the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
availability and cost of seismic, drilling and other equipment; ability of the
Company to complete its capital programs; 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 ability of
the Company to attract the necessary labour required to build its projects;
operating hazards and other difficulties inherent in the exploration for and
production and sale of crude oil and natural gas; availability and cost of
financing; success of exploration and development activities; timing and
success of integrating the business and operations of acquired companies;
production levels; uncertainty of reserve estimates; actions by governmental
authorities; government regulations and the expenditures required to comply
with them (especially safety and environmental laws and regulations); asset
retirement obligations; 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, and the Company'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 were 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. Except as required by law, the
Company assumes no obligation to update forward-looking statements should
circumstances or the Company's estimates or opinions change.
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
Management's discussion and analysis includes references to financial measures
commonly used in the crude oil and natural gas industry, such as cash flow
from operations, adjusted net earnings from operations, 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 activities).
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 its performance. 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.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") of the financial condition and
results of operations of the Company should be read in conjunction with the
Company's audited consolidated financial statements and related notes for the
year ended December 31, 2005. The consolidated financial statements have been
prepared in accordance with Canadian GAAP. A reconciliation of Canadian GAAP
to United States GAAP is included in note 15 to the consolidated financial
statements. All dollar amounts are referenced in Canadian dollars, except
where otherwise noted. Common share data has been restated to reflect the
two-for-one share split in May 2005. The calculation of barrels of oil
equivalent ("boe") is based on a conversion ratio of six thousand cubic feet
("mcf") of natural gas to one barrel ("bbl") of crude oil to estimate relative
energy content. This conversion may be misleading, particularly when used in
isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at
the burner tip and does not represent the value equivalency at the well head.
Production volumes are the Company's interest before royalties, and realized
prices exclude the effect of risk management activities, except where noted
otherwise. The following discussion and analysis refers primarily to the
Company's 2005 financial results compared to 2004 and 2003, unless otherwise
indicated. In addition, this discussion details the Company's capital program
and outlook for 2006. This MD&A is dated February 21, 2006.
Management's Discussion & Analysis 45
ABBREVIATIONS
AECO Alberta natural gas reference location
AIF Annual Information Form
bbl barrel
bbl/d barrels per day
BCF billion cubic feet
bcf/d billion cubic feet per day
BOE barrels of oil equivalent
boe/d barrels of oil equivalent per day
C$ Canadian dollars
FPSO Floating Production, Storage and Offtake Vessel
GHG Greenhouse Gas
Horizon Project Horizon Oil Sands Project
mbbl thousand barrels
mbbl/d thousand barrels per day
mboe thousand barrels of oil equivalent
mboe/d thousand barrels of oil equivalent per day
mcf thousand cubic feet
mcf/d thousand cubic feet per day
mmbbl million barrels
mmboe million barrels of oil equivalent
mmbtu million British thermal units
mmcf/d million cubic feet per day
NGLs Natural gas liquids
NYMEX New York Mercantile Exchange
NYSE New York Stock Exchange
SCO Synthetic light crude oil
SEC Securities and Exchange Commission
TSX Toronto Stock Exchange
UK United Kingdom
US United States
US$ United States dollars
WCS Western Canadian Select crude oil blend
WTI West Texas Intermediate
OBJECTIVE AND STRATEGY
The Company's objective is to increase crude oil and natural gas production,
reserves, cash flow and net asset value (1) on a per common share basis
through the development of its existing crude oil and natural gas properties
and through the discovery and acquisition of new reserves. The Company
accomplishes this objective by having a defined growth and a value enhancement
plan for each of its products and segments. The Company takes a balanced
approach to growth and investments and focuses on creating long-term
shareholder wealth. The Company effectively allocates its capital by
maintaining:
o Balance among its products, namely natural gas, light crude oil,
Pelican Lake crude oil (2), primary heavy crude oil and thermal
heavy crude oil;
o Balance among near-, mid- and long-term projects;
o Balance among acquisitions, exploitation and exploration; and,
o Balance between sources of debt and by maintaining a strong balance
sheet.
(1) Discounted value of conventional crude oil and natural gas reserves and
undeveloped land, less net debt.
(2) Pelican Lake crude oil is 14-17 (degree) API oil, but receives medium
quality crude netbacks due to low operating costs and low royalty rates.
The Company's three-phase crude oil marketing strategy includes:
o Blending various crude oil streams with diluents into more
attractive feedstock;
o Supporting and participating in pipeline expansion or new additions;
and
o Supporting and participating in projects that will increase the
conversion capacity of heavy crude oil.
Operational discipline and cost control is central to the Company's strategy.
By controlling costs consistently throughout all cycles of the industry, the
Company believes that it will achieve continued growth. Cost control is
attained by developing area knowledge, by core area domination and by
maintaining a high working interest in its properties.
The Company is committed to maintaining its strong financial position
throughout construction of the Horizon Oil Sands Project ("Horizon Project").
The Company believes that it has built the necessary financial capacity to
complete the Horizon Project while at the same time not compromising delivery
from its conventional crude oil and natural gas growth opportunities.
Additionally, the Company's risk management hedge program has been expanded to
reduce the risk of volatility in commodity price markets and to support the
Company's cash flow for its capital expenditures program throughout the
construction period of the Horizon Project.
Strategic accretive acquisitions are a key component of the Company's
strategy. The Company has used a combination of internally generated cash
flows and debt to selectively acquire properties generating future cash flows
in its core regions. These targeted acquisitions provide relatively quick
repayment of initial investments and should provide additional free cash flow
during the construction years of the Horizon Project while still achieving
targeted returns.
The year ended December 31, 2005, was another successful year in the execution
of the Company's strategy. Highlights are as follows:
o Maintained strong levels of net earnings;
o Achieved record levels of adjusted net earnings from operations;
o Achieved record levels of cash flow;
o Completed the disposition of a large portion of its overriding
royalty interests, which were considered non-core to the Company's
operations, for proceeds of approximately $345 million;
o Completed the subdivision of its common shares on the basis of two
for one;
o Increased the quarterly dividend by 20% to $0.06 per common share;
o Purchased 850,000 common shares for a total cost of $45 million
under the Company's Normal Course Issuer Bid;
o Achieved record levels of natural gas and crude oil and NGLs
production;
o Achieved its annual production guidance for crude oil and NGLs, and
natural gas;
o Completed the development of the 57.61% owned and operated Baobab
Field offshore Cote d'lvoire West Africa, which commenced production
on August 9, 2005 at approximately 30,000 bbl/d net to the Company;
o Completed the acquisition of the permit to develop the Olowi Field,
offshore Gabon, West Africa with development plans to proceed in
2006;
o Received Board of Directors' approval of the Horizon Project and
completed 19% of Phase 1 construction;
46 Management's Discussion & Analysis
o Signed a key pipeline transportation agreement, which will allow
Horizon Project Synthetic Crude Oil ("SCO") to reach the pipeline
hub at Edmonton, Alberta;
o Completed all major 2005 milestones on the Horizon Project, before
winter' onset;
o Commenced steam injection at Primrose North. First oil production
began in January 2006 and is expected to increase to 30,000 bbl/d by
the third quarter of 2006;
o Drilled a record 1,634 net wells, excluding stratigraphic
test/service wells; and
o Announced a strategy to review the building of a 100% owned and
operated upgrader ("Canadian Natural Upgrader") for the Company's
in-situ oil sands assets in the Cold Lake to Athabasca region.
NET EARNINGS AND CASH FLOW FROM OPERATIONS
-----------------------------------------------------------------------------------------------------
FINANCIAL HIGHLIGHTS ($ millions, except per
common share amounts) 2005 2004 2003
-----------------------------------------------------------------------------------------------------
Revenue, before royalties $ 10,107 $ 7,547 $ 6,155
Net earnings $ 1,050 $ 1,405 $ 1,403
Per common share
- basic (1) $ 1.96 $ 2.62 $ 2.62
- diluted (1) $ 1.95 $ 2.60 $ 2.53
Adjusted net earnings from operations (2) $ 2,034 $ 1,405 $ 987
Per common share
- basic (1) $ 3.79 $ 2.62 $ 1.84
- diluted (1) $ 3.78 $ 2.60 $ 1.80
Cash flow from operations (3) $ 5,021 $ 3,769 $ 3,160
Per common share
- basic (1) $ 9.36 $ 7.03 $ 5.88
- diluted (1) $ 9.33 $ 6.98 $ 5.76
Dividends declared per common share $ 0.236 $ 0.200 $ 0.150
Total assets $ 21,852 $ 18,372 $ 14,643
Total long-term liabilities $ 9,790 $ 9,196 $ 7,277
Capital expenditures, net of dispositions $ 4,932 $ 4,633 $ 2,506
=====================================================================================================
(1) Restated to reflect two-for-one share split in May 2005.
(2) Adjusted net earnings from operations is a non-GAAP term that represents
net earnings adjusted for certain items of a non-operational nature. The
Company evaluates its performance based on adjusted net earnings from
operations. The following reconciliation lists the after-tax effects of
certain items of a non-operational nature that are included in the
Company's financial results. Adjusted net earnings from operations may
not be comparable to similar measures presented by other companies.
---------------------------------------------------------------------------------------------------
($ millions) 2005 2004 2003
---------------------------------------------------------------------------------------------------
Net earnings as reported $ 1,050 $ 1,405 $ 1,403
Stock-based compensation, net of tax (a) 481 168 136
Unrealized risk management loss (gain),
net of tax (b) 607 (27) -
Unrealized foreign exchange gain, net
of tax (c) (85) (75) (274)
Effect of statutory tax rate changes on
future income tax liabilities (d) (19) (66) (278)
---------------------------------------------------------------------------------------------------
Adjusted net earnings from operations $ 2,034 $ 1,405 $ 987
===================================================================================================
(a) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the intrinsic value of the outstanding vested
options is recorded as a liability on the Company's balance sheet
and periodic changes in the intrinsic value, net of taxes, flow
through net earnings.
(b) Effective January 1, 2004, the Company adopted a new accounting
standard whereby financial instruments not designated as hedges are
recorded at fair value on its balance sheet, with changes in fair
value, net of taxes, flowing through net earnings. The amounts
ultimately realized may be materially different than reflected in
the financial statements due to changes in prices of the underlying
items hedged, primarily crude oil and natural gas.
(c) Unrealized foreign exchange gains and losses result primarily from
the translation of US dollar denominated long-term debt to
period-end exchange rates and are immediately recognized in net
earnings.
(d) All substantively enacted adjustments in applicable income tax rates
are applied to underlying assets and liabilities on the Company's
balance sheet in determining future income tax assets and
liabilities. The impact of these tax rate changes is recorded in net
earnings during the period the legislation is substantively enacted.
In 2005, the province of British Columbia enacted legislation to
reduce its corporate income tax rate by 1.5%. During 2004, the
province of Alberta enacted legislation to reduce its corporate
income tax rate by 1%. During 2003 the province of Alberta enacted
legislation to reduce its corporate income tax rate by 0.5%. Also
during 2003, the Canadian federal government enacted legislation to
change the taxation of resource income. The federal legislation
reduces the corporate income tax rate on resource income from 28% to
21% over five years beginning January 1, 2003. Over the same period
the deduction for resource allowance is being phased out and a
deduction of actual crown royalties paid is being phased in. The
Company's future income tax liability was reduced by $31 million
with respect to the Alberta corporate income tax rate reduction and
by $247 million with respect to the federal resource income tax rate
changes.
(3) Cash flow from operations is a non-GAAP term that represents net earnings
adjusted for non-cash items. The Company evaluates its performance based
on cash flow from operations. The Company considers cash flow from
operations a key measure as it demonstrates the Company's ability to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Cash flow from operations may not be
comparable to similar measures presented by other companies.
---------------------------------------------------------------------------------------------------
($ millions) 2005 2004 2003
---------------------------------------------------------------------------------------------------
Net earnings $ 1,050 $ 1,405 $ 1,403
Non-cash items:
Depletion, depreciation and amortization 2,013 1,769 1,509
Asset retirement obligation accretion 69 51 62
Stock-based compensation 723 249 200
Unrealized risk management activities 925 (40) -
Unrealized foreign exchange gain (103) (94) (343)
Deferred petroleum revenue tax recovery (9) (45) (9)
Future income tax 353 474 338
---------------------------------------------------------------------------------------------------
Cash flow from operations $ 5,021 $ 3,769 $ 3,160
===================================================================================================
Management's Discussion & Analysis 47
The Company achieved record levels of cash flow from operations and
production in 2005 as a result of strong operational performance combined with
increased commodity prices. The strong operating results are attributable to
the Company following its defined growth strategy and to the strong asset base
the Company has developed over time through organic growth and accretive
acquisitions.
For the year ended December 31, 2005, the Company recorded net earnings of
$1,050 million compared to net earnings of $1,405 million for the year ended
December 31, 2004 (2003 - $1,403 million). Net earnings for 2005 include
unrealized after-tax expenses of $984 million related to the Company's risk
management activities and stock-based compensation plans, net of foreign
exchange gains and the effect of statutory tax rate changes ($nil for 2004;
2003 -unrealized after-tax income of $416 million). Excluding the effects of
these items, adjusted net earnings from operations increased 45% to $2,034
million from $1,405 million in 2004 (2003 - $987 million) due to continuing
strong crude oil and natural gas prices as well as record levels of total
sales on a boe basis, offset by realized risk management activities and the
impact of a strengthening Canadian dollar.
Cash flow from operations reached record levels in 2005. Cash flow from
operations increased 33% to $5,021 million ($9.36 per common share), up from
$3,769 million ($7.03 per common share) in 2004 (2003 - $3,160 million or
$5.88 per common share). The increase in cash flow from operations was due
mainly to strong commodity prices and record levels of total sales volume on a
boe basis, offset by realized risk management activities and the impact of a
strengthening Canadian dollar. In 2005, the Company's average sales price per
bbl of crude oil and NGLs increased 23% to $46.86 per bbl from $37.99 per bbl
in 2004 (2003 - $32.66 per bbl). The Company's average natural gas price
increased 32% to $8.57 per mcf from $6.50 per mcf in 2004 (2003 - $6.21 per
mcf).
Production volumes before royalties increased 8% to a record 552,960 boe/d, up
from 513,835 boe/d in 2004 (2003 - 458,814 boe/d). The increase in production
was due to organic growth from the Company's extensive North America capital
expenditure program and the commencement of production from the Baobob Field
offshore Cote d'lvoire, as well as the full year impact of accretive
acquisitions completed in 2004. Production of crude oil and NGLs before
royalties increased 11% to 313,168 bbl/d, up from 282,489 bbl/d in 2004 (2003
- 242,392 bbl/d). Natural gas production before royalties increased 4% to
1,439 mmcf/d, up from 1,388 mmcf/d in 2004 (2003 - 1,299 mmcf/d).
---------------------------------------------------------------------------------------------------
OPERATING HIGHLIGHTS 2005 2004 2003
---------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
Sales price (2) $ 46.86 $ 37.99 $ 32.66
Royalties 3.97 3.16 2.77
Production expense 11.17 10.05 10.28
---------------------------------------------------------------------------------------------------
Netback $ 31.72 $ 24.78 $ 19.61
---------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
Sales price (2) $ 8.57 $ 6.50 $ 6.21
Royalties 1.75 1.35 1.32
Production expense 0.73 0.67 0.60
---------------------------------------------------------------------------------------------------
Netback $ 6.09 $ 4.48 $ 4.29
---------------------------------------------------------------------------------------------------
BARREL OF OIL EQUIVALENT ($/boe) (1)
Sales price (2) $ 48.77 $ 38.45 $ 34.84
Royalties 6.82 5.37 5.20
Production expense 8.21 7.35 7.15
---------------------------------------------------------------------------------------------------
Netback $ 33.74 $ 25.73 $ 22.49
---------------------------------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Including transportation costs and excluding risk management activities.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the most
recently completed quarters: ($ millions, except per common share amounts)
----------------------------------------------------------------------------------------------------------------------------
2005 TOTAL DEC 31 SEP 30 JUN 30 MAR 31
----------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 10,107 $ 3,032 $ 2,918 $ 2,164 $ 1,993
Net earnings (loss) $ 1,050 $ 1,104 $ 151 $ 219 $ (424)
Net earnings (loss) per common share
- basic (1) $ 1.96 $ 2.06 $ 0.28 $ 0.41 $ (0.79)
- diluted (1) $ 1.95 $ 2.06 $ 0.28 $ 0.41 $ (0.79)
============================================================================================================================
----------------------------------------------------------------------------------------------------------------------------
2004 TOTAL DEC 31 SEP 30 JUN 30 MAR 31
----------------------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 7,547 $ 1,969 $ 2,075 $ 1,865 $ 1,638
Net earnings $ 1,405 $ 577 $ 311 $ 259 $ 258
Net earnings per common share
- basic (1) $ 2.62 $ 1.07 $ 0.58 $ 0.48 $ 0.49
- diluted (1) $ 2.60 $ 1.06 $ 0.57 $ 0.48 $ 0.48
=============================================================================================================================
(1) Restated to reflect two-for-one share split in May 2005.
48 Management's Discussion & Analysis
Quarterly revenues have steadily increased throughout 2004 and 2005. This
trend reflects increasing world benchmark crude oil and natural gas prices
and increasing sales volumes.
o Prices continued to reflect world-wide economic growth and
persistent geopolitical uncertainty, further exacerbated by
hurricane activity in the Gulf of Mexico during the third quarters
of 2004 and 2005. As a result, the Company's realized crude oil and
NGLs price increased from C$34.21 per bbl for the first quarter of
2004 to C$46.38 per bbl for the fourth quarter of 2005. The realized
natural gas price increased from C$6.31 per mcf to C$11.67 per mcf
for the same periods. A strengthening Canadian dollar relative to
the US dollar offset the impact of increasing commodity prices. The
US / Canadian dollar average exchange rate increased from 0.76 for
the first quarter of 2004 to 0.84 for the fourth quarter of 2005.
o Strong sales volumes in 2005 versus 2004 were also fundamental to
the steady increase in revenue, driven by North America's extensive
capital program, the commencement of production from the Baobab
Field offshore Cote d'lvoire in 2005, as well as the full year
impact of accretive acquisitions completed late in 2004. Daily
production increased from 476,944 boe/d day in the first quarter of
2004 to 577,505 boe/d for the fourth quarter of 2005.
o The Company acquired certain heavy crude oil properties in its
Northern Plains core region in the first quarter of 2004.
o The Company completed the acquisition of certain resource properties
located in Northeast British Columbia and Northwest Alberta in the
second quarter of 2004. These properties include further ownership
in the Ladyfern natural gas field.
o The Company acquired certain light crude oil producing properties in
the Central North Sea in the third quarter of 2004. The acquired
properties comprise operated interests in T-Block (Tiffany, Toni and
Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields).
o The Company completed the acquisition of certain resource properties
located in Alberta, British Columbia and Saskatchewan in the fourth
quarter of 2004.
In addition to commodity prices, sales volumes and acquisitions, net earnings
continued to be impacted by:
o The impact of the mark-to-market ("MTM") treatment of the Company's
commodity price contracts as part of its commodity hedging program.
Steadily increasing commodity prices have resulted in significant
realized and unrealized risk management losses as the Company
strives to lock in prices and secure cash flow for its capital
expenditure program.
o The MTM treatment on its stock-based compensation plan. The
Company's strong stock performance has resulted in the recognition
of significant stock-based compensation expense.
o Increasing production expense. Higher service costs as a result of
increased industry-wide activity in reaction to higher commodity
prices as well as the impact of higher crude oil prices on fuel
related expenses have resulted in increased costs.
o Corporate income tax rates. During the first quarter of 2004, the
North America future tax liability was reduced by $66 million as a
result of a reduction in the Alberta corporate income tax rate from
12.5% to 11.5%. During the third quarter of 2005, the province of
British Columbia enacted legislation to reduce its corporate income
tax rate by 1.5% effective July 1, 2005. As a result, the North
America future income tax liability was reduced by $19 million.
BUSINESS ENVIRONMENT
---------------------------------------------------------------------------------------------------
(Yearly average) 2005 2004 2003
---------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) (1) $ 56.61 $ 41.43 $ 31.02
Dated Brent benchmark price (US$/bbl) $ 54.45 $ 38.28 $ 28.83
Differential to LLB blend (US$/bbl) $ 20.83 $ 13.44 $ 8.55
Differential to LLB blend as a % of WTI 37% 32% 28%
Condensate benchmark price (US$/bbl) $ 57.25 $ 41.62 $ 31.42
NYMEX benchmark price (US$/mmbtu) $ 8.56 $ 6.09 $ 5.44
AECO benchmark price (C$/GJ) $ 8.05 $ 6.43 $ 6.35
US/Canadian dollar average exchange rate (US$) 0.8253 0.7683 0.7135
===================================================================================================
(1) Refers to West Texas Intermediate crude oil barrel prices at Cushing,
Oklahoma.
World light crude oil prices reached all-time highs in 2005, supported by:
o Strong demand growth, particularly in China, India and the United
States;
o Ongoing geopolitical uncertainties in Iran, Nigeria, Iraq and
Venezuela;
o Production losses in the Gulf of Mexico from hurricanes Katrina and
Rita. Many platforms and refineries are not expected to be
operational until sometime late in 2006; and
o Restricted crude oil refining capacity, which increased refiners'
demand for light crude oil to maximize yields of gasoline and
distillates.
Management's Discussion & Analysis 49
West Texas Intermediate ("WTI") averaged US$56.61 per bbl for the year ended
December 31, 2005, an increase of 37% compared to US$41.43 per bbl for the
year ended December 31, 2004 (2003 - US$31.02 per bbl).
Higher WTI pricing is not fully reflected in the Company's crude oil price
realizations. The positive impact of higher WTI prices on the Company's crude
oil production continues to be mitigated by wider heavy crude oil
differentials, which increased 55% to US$20.83 per bbl for the year ended
December 31, 2005 from US$13.44 per bbl for the year ended December 31, 2004
(2003 - $US8.55 per bbl).
Heavy crude oil differentials in 2005 continued to be higher than the
long-term average primarily due to physical limitations for demand at
refineries. Following hurricanes Katrina and Rita, refiners sought to process
lighter barrels to increase their yields of gasoline and distillates, which
resulted in the further deterioration of heavy crude oil differentials. Plant
turnarounds and maintenance during the year, additional problems at refineries
and upgraders, the higher cost of diluents, and the stronger Canadian dollar
also mitigated the effect of higher WTI prices on the Company's heavy crude
oil price realizations. A strengthening in the Canadian dollar reduces the
Canadian dollar sales price the Company receives for its crude oil production
as crude oil prices are based on US dollar denominated benchmarks.
North American natural gas prices also climbed in 2005 due to concerns around
supply as well as the impact of higher crude oil prices. NYMEX natural gas
prices increased 41% to average US$8.56 per mmbtu for the year ended December
31, 2005, up from US$6.09 per mmbtu for the year ended December 31, 2004 (2003
- $5.44 per mmbtu). AECO natural gas pricing moved directionally with NYMEX,
increasing 25% to average $8.05 per GJ for the year ended December 31, 2005,
up from $6.43 per GJ for the year ended December 31, 2004 (2003 - $6.35 per
GJ).
REVENUE, BEFORE ROYALTIES
Analysis of changes in revenue, before royalties
---------------------------------------------------------------------------------------------------------------------------------
Changes due to Changes due to
($ millions) 2003 Volumes Prices Other 2004 Volumes Prices Other 2005
---------------------------------------------------------------------------------------------------------------------------------
North America
Crude oil and NGLs $ 1,953 $ 342 $ 283 $ -- $ 2,578 $ 170 $ 546 $ -- $ 3,294
Natural gas 3,068 207 126 -- 3,401 208 1,029 -- 4,638
---------------------------------------------------------------------------------------------------------------------------------
5,021 549 409 -- 5,979 378 1,575 -- 7,932
---------------------------------------------------------------------------------------------------------------------------------
North Sea
Crude oil and NGLs 873 123 227 -- 1,223 31 382 -- 1,636
Natural gas 80 5 9 -- 94 (59) (12) -- 23
---------------------------------------------------------------------------------------------------------------------------------
953 128 236 -- 1,317 (28) 370 -- 1,659
---------------------------------------------------------------------------------------------------------------------------------
Offshore West Africa
Crude oil and NGLs 141 13 54 -- 208 182 86 -- 476
Natural gas 14 (1) 1 -- 14 (6) 1 -- 9
---------------------------------------------------------------------------------------------------------------------------------
155 12 55 -- 222 176 87 -- 485
---------------------------------------------------------------------------------------------------------------------------------
Subtotal
Crude oil and NGLs 2,967 478 564 -- 4,009 383 1,014 -- 5,406
Natural gas 3,162 211 136 -- 3,509 143 1,018 -- 4,670
---------------------------------------------------------------------------------------------------------------------------------
6,129 689 700 -- 7,518 526 2,032 -- 10,076
Midstream 61 -- -- 7 68 -- -- 9 77
Intersegment eliminations
and other (1) (35) -- -- (4) (39) -- -- (7) (46)
---------------------------------------------------------------------------------------------------------------------------------
Total $ 6,155 $ 689 $ 700 $ 3 $ 7,547 $ 526 $ 2,032 $ 2 $ 10,107
=================================================================================================================================
(1) Eliminates primarily internal transportation and electricity charges.
Revenue rose 34% to $10,107 million in 2005, up from $7,547 million in 2004
(2003 - $6,155 million). Price increases accounted for 79% of the 2005
increase (2004 - 51%), while volume increases accounted for the remaining 21%
(2004 - 49%).
In 2005, 21% of the Company's crude oil and natural gas revenue was generated
outside of North America, up from 20% in 2004 (2003 - 18%). North Sea
accounted for 16% of crude oil and natural gas revenue in 2005 and 17% in 2004
(2003 - 16%), and Offshore West Africa accounted for 5% of crude oil and
natural gas revenue in 2005 and 3% in 2004 (2003 - 2%).
50 Management's Discussion & Analysis
---------------------------------------------------------------------------------------------------
ANALYSIS OF PRODUCT PRICES (1) 2005 2004 2003
---------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (2)
North America $ 39.62 $ 33.16 $ 29.40
North Sea $ 66.57 $ 51.37 $ 42.00
Offshore West Africa $ 59.91 $ 49.05 $ 36.47
Company average $ 46.86 $ 37.99 $ 32.66
---------------------------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (2)
North America $ 8.65 $ 6.61 $ 6.34
North Sea $ 3.17 $ 3.73 $ 3.03
Offshore West Africa $ 5.91 $ 5.25 $ 4.37
Company average $ 8.57 $ 6.50 $ 6.21
---------------------------------------------------------------------------------------------------
Company average ($/boe) (2) $ 48.77 $ 38.45 $ 34.84
---------------------------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (excluding midstream
revenue)
Crude oil and NGLs 54% 54% 50%
Natural gas 46% 46% 50%
===================================================================================================
(1) Including transportation costs and excluding risk management activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Realized crude oil prices increased 23% to average $46.86 per bbl in 2005, up
from $37.99 per bbl in 2004 (2003 - $32.66 per bbl). This increase was
primarily due to higher benchmark world crude oil prices, as well as an
increased proportion of crude oil and NGLs sales coming from Offshore West
Africa, offset by higher heavy crude oil differentials and a stronger Canadian
dollar. Higher benchmark crude oil prices were primarily driven by increased
demand in countries such as China, India and the United States as well as
concerns around supply, which increased pricing volatility.
The Company's realized natural gas price increased 32% to average $8.57 per
mcf in 2005, up from $6.50 per mcf in 2004 (2003 - $6.21 per mcf), primarily
due to supply concerns and a continued strengthening in benchmark North
America gas pricing.
NORTH AMERICA
North America realized crude oil prices increased 19% to average $39.62 per
bbl in 2005, up from $33.16 per bbl in 2004 (2003 - $29.40 per bbl). The
increase in the realized crude oil price in 2005 was mainly due to higher
benchmark crude oil prices, partially offset by wider heavy crude oil
differentials and the strengthening Canadian dollar.
North America continues to focus on its crude oil marketing strategy,
including the development of a blending strategy that expands markets within
current pipeline infrastructure, supporting pipeline projects that will
provide capacity to transport crude oil to new geographic markets, and working
with refiners to add incremental heavy crude oil conversion capacity. As part
of an industry initiative to develop new blends of Western Canadian crude
oils, the Company has access to blending capacity of up to 140,000 bbl/d. The
Company is currently contributing approximately 139,000 bbl/d of heavy crude
oil blends to the Western Canadian Select ("WCS") stream, a new blend of up to
10 different crude oil streams. WCS resembles a Bow River type crude with
distillation cuts approximating a natural heavy crude oil with premium quality
asphalt characteristics and has an API of 19(degree)-22(degree). Volumes of
the new blend are expected to grow, with the potential to become a new
benchmark for North American markets in addition to WTI. The Company has
committed to 25,000 bbl/d of capacity on the Corsicana Pipeline, which will
carry crude oil to the Gulf of Mexico and is expected to be in operation late
in the first quarter of 2006. The Corsicana Pipeline is made up of a series
of segments extending from Patoka Illinois to Nederland Texas, near the US
Gulf Coast.
North America realized natural gas prices increased 31% to average $8.65 per
mcf for the year ended December 31, 2005, up from $6.61 per mcf for the year
ended December 31, 2004 (2003 - $6.34 per mcf). This increase was due to
supply concerns and fluctuations in the North America benchmark natural gas
price in response to crude oil pricing.
A comparison of the price received for the Company's North America production
is as follows:
---------------------------------------------------------------------------------------------------
2005 2004 2003
---------------------------------------------------------------------------------------------------
Wellhead price (1)(2)
Light crude oil and NGLs (C$/bbl) $ 58.41 $ 45.90 $ 37.59
Pelican Lake crude oil (C$/bbl) $ 38.39 $ 32.12 $ 28.05
Primary heavy crude oil (C$/bbl) $ 33.53 $ 28.99 $ 26.21
Thermal heavy crude oil (C$/bbl) $ 32.29 $ 29.00 $ 25.56
Natural gas (C$/mcf) $ 8.65 $ 6.61 $ 6.34
===================================================================================================
(1) Including transportation costs and excluding risk management activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Management's Discussion & Analysis 51
NORTH SEA
North Sea realized crude oil prices increased 30% to average $66.57 per bbl
for the year ended December 31, 2005, up from $51.37 per bbl for the year
ended December 31, 2004 (2003 - $42.00 per bbl). The increase in the realized
crude oil price compared to 2004 was due mainly to higher world benchmark
crude oil prices and a narrowing of the average Brent differential, offset by
the strengthening Canadian dollar.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 22% to average $59.91
per bbl for the year ended December 31, 2005, an increase from $49.05 per bbl
for the year ended December 31, 2004 (2003 - $36.47 per bbl). The increase in
realized crude oil prices from 2004 was primarily due to higher world
benchmark crude oil prices offset by the strengthening Canadian dollar.
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title
transfers to the customer and delivery has taken place, referred to as
"liftings" in this MD&A. For production where revenue has not yet been
recognized, the related crude oil inventory volumes, by segment, were as
follows at December 31, 2005:
-------------------------------------------------------------------------------------------------------------------------------
(bbl) 2005
-------------------------------------------------------------------------------------------------------------------------------
North America, related to Corsicana pipeline line fill 484,157
North Sea, related to timing of liftings 747,141
Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil 412,841
-------------------------------------------------------------------------------------------------------------------------------
1,644,139
===============================================================================================================================
At December 31, 2004, variances between production volumes and liftings were
not significant.
---------------------------------------------------------------------------------------------------
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES 2005 2004 2003
---------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 221,669 206,225 174,895
North Sea 68,593 64,706 56,869
Offshore West Africa 22,906 11,558 10,628
---------------------------------------------------------------------------------------------------
313,168 282,489 242,392
---------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,416 1,330 1,245
North Sea 19 50 46
Offshore West Africa 4 8 8
---------------------------------------------------------------------------------------------------
1,439 1,388 1,299
---------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 552,960 513,835 458,814
---------------------------------------------------------------------------------------------------
PRODUCT MIX (%)
Light crude oil and NGLs 26% 24% 25%
Pelican Lake crude oil 4% 4% 5%
Primary heavy crude oil 17% 19% 15%
Thermal heavy crude oil 10% 8% 8%
Natural gas 43% 45% 47%
===================================================================================================
---------------------------------------------------------------------------------------------------
DAILY PRODUCTION, NET OF ROYALTIES 2005 2004 2003
---------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS (bbl/d)
North America 191,751 180,011 152,444
North Sea 68,487 64,598 56,928
Offshore West Africa 22,293 11,221 10,314
---------------------------------------------------------------------------------------------------
282,531 255,830 219,686
---------------------------------------------------------------------------------------------------
NATURAL GAS (mmcf/d)
North America 1,125 1,048 976
North Sea 18 50 46
Offshore West Africa 4 7 8
---------------------------------------------------------------------------------------------------
1,147 1,105 1,030
---------------------------------------------------------------------------------------------------
TOTAL BARREL OF OIL EQUIVALENT (boe/d) 473,742 440,022 391,361
===================================================================================================
Daily production and per barrel statistics are presented throughout this MD&A
on a "before royalty" or "gross" basis. Production net of royalties is
presented for information purposes only.
52 Management's Discussion & Analysis
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light crude oil and NGLs, Pelican Lake crude oil, primary heavy
crude oil and thermal heavy crude oil.
Record levels of total crude oil and natural gas production averaged 552,960
boe/d for the year ended December 31, 2005, an increase of 8% or 39,125 boe/d
from 513,835 boe/d for the year ended December 31, 2004 (2003 - 458,814
boe/d). The increase in production year over year was due to organic growth
from the Company's extensive North America capital expenditure program and the
commencement of production from the Baobab Field offshore Cote d'Ivoire in
2005, as well as the full year impact of accretive acquisitions completed in
2004.
Total record crude oil and NGLs production for the year ended December 31,
2005 increased 11% to 313,168 bbl/d from 282,489 bbl/d for the year ended
December 31, 2004 (2003 - 242,392 bbl/d). Crude oil and NGLs production for
2005 was in line with the Company's guidance of 308,000 to 316,000 bbl/d.
Natural gas production continues to represent the Company's largest product
offering. Natural gas production for the year ended December 31, 2005
increased 4% or 51 mmcf/d to average 1,439 mmcf/d compared to 1,388 mmcf/d for
the year ended December 31, 2004 (2003 - 1,299 mmcf/d). Growth in natural gas
production in Western Canada was negatively affected by the early arrival of
spring breakup and weather related delays due to unusually wet conditions as
well as an overall increase in industry activity. The market for the necessary
oilfield services and material has become increasingly competitive, resulting
in drilling, completion, tie-in and maintenance delays. Natural gas production
for 2005 was in line with the Company's guidance of 1,436 to 1,448 mmcf/d.
The Company expects annual production levels in 2006 to average 1,468 to 1,551
mmcf/d of natural gas and 335,000 to 373,000 bbl/d of crude oil and NGLs.
First quarter 2006 production is expected to be between 1,426 and 1,475 mmcf/d
of natural gas and 306,000 to 334,000 bbl/d of crude oil and NGLs.
NORTH AMERICA
North America crude oil and NGLs production for the year ended December 31,
2005 increased 7% or 15,444 bbl/d to average 221,669 bbl/d, up from 206,225
bbl/d for the year ended December 31, 2004 (2003 - 174,895 bbl/d). The
increase in crude oil and NGLs production was mainly due to the timing of
Primrose production cycles and the positive results of the Pelican Lake
waterflood project.
North America natural gas production for the year ended December 31, 2005
increased 6% or 86 mmcf/d to average 1,416 mmcf/d, up from 1,330 mmcf/d in
2004 (2003 - 1,245 mmcf/d). Natural gas production increased as a result of
organic growth and the full year impact of accretive property acquisitions in
2004, but was negatively impacted by the early arrival of spring breakup and
weather related delays due to unusually wet conditions during the summer
months. In addition to weather related factors, production growth was also
negatively impacted by the increased demand for oilfield services and
materials, which caused delays in the timing of production being brought on
stream.
NORTH SEA
North Sea crude oil production for the year ended December 31, 2005 was 68,593
bbl/d, an increase of 6% from 64,706 bbl/d for 2004 (2003 - 56,869 bbl/d).
Production levels were in line with expectations, reflecting anticipated
curtailments at the Lyell Field and the Columba B and E Terraces, continued
restrictions at Murchison Field due to third party natural gas export
facilities and production declines at the satellite Playfair Field.
Natural gas production in the North Sea for the year ended December 31, 2005
decreased 62% to average 19 mmcf/d, down from 50 mmcf/d for the year ended
December 31, 2004 (2003 - 46 mmcf/d). The decrease in natural gas production
was due to the commencement of the natural gas reinjection program in the
Banff Field in the Central North Sea late in 2004. The natural gas reinjection
project is expected to result in an overall increase in the reservoir
recovery, but resulted in reductions in natural gas production in 2005.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production for the year ended December 31, 2005
increased 98% to 22,906 bbl/d from 11,558 bbl/d for the year ended December
31, 2004 (2003 - 10,628 bbl/d). The production increase was primarily due to
commencement of production from the 57.61% owned and operated Baobab Field in
August 2005, as well as increased production from additional infill wells
drilled in East Espoir.
Management's Discussion & Analysis 53
ROYALTIES 2005 2004 2003
------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 5.37 $ 4.21 $ 3.79
North Sea $ 0.10 $ 0.08 $(0.03)
Offshore West Africa $ 1.62 $ 1.43 $ 1.08
Company average $ 3.97 $ 3.16 $ 2.77
------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America $ 1.78 $ 1.40 $ 1.38
North Sea $ -- $ -- $ --
Offshore West Africa $ 0.16 $ 0.15 $ 0.13
Company average $ 1.75 $ 1.35 $ 1.32
------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1) $ 6.82 $ 5.37 $ 5.20
------------------------------------------------------------------------------
PERCENTAGE OF REVENUE (2)
Crude oil and NGLs 8% 8% 9%
Natural gas 20% 21% 21%
Boe 14% 14% 15%
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
NORTH AMERICA
North America crude oil and NGLs royalties per bbl for the year ended December
31, 2005 increased from 2004 primarily due to higher benchmark crude oil
prices, offset by wider heavy crude oil differentials and a strengthening
Canadian dollar. Royalty rates are expected to increase in the future as a
result of the Primrose South Field payout expected to occur late in 2006 or
early 2007.
Natural gas royalties increased from 2004 due to higher benchmark natural gas
prices, offset by a stronger Canadian dollar and adjustments to royalty rates
related to prior years.
NORTH SEA
North Sea government royalties on crude oil were eliminated effective January
1, 2003. The remaining North Sea royalty represents a gross overriding royalty
on the Ninian Field. In 2003, the Company received a refund of royalties
previously provided.
OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of Production Sharing
Contracts ("PSCs"). Under the PSCs, revenues are divided into cost recovery
revenue and profit revenue. Cost recovery revenue allows the Company to
recover its capital and operating costs and the costs carried by the Company
on behalf of the Government State Oil Company. Profit revenue is allocated to
the joint venture partners in accordance with their respective equity
interests, after a portion has been allocated to the Government. These
revenues are reported as sales revenue. The Government's share of profit
revenue attributable to the Company's equity interest is allocated to royalty
expense and current income tax expense in accordance with the PSCs. Based on
current projections, the Espoir Field and the Baobab Field are expected to
reach payout in 2007, which will increase royalty rates and current income
taxes in accordance with the PSCs.
PRODUCTION EXPENSE 2005 2004 2003
------------------------------------------------------------------------------
CRUDE OIL AND NGLS ($/bbl) (1)
North America $ 10.49 $ 8.94 $ 9.14
North Sea $ 14.94 $ 14.03 $ 14.07
Offshore West Africa $ 6.50 $ 7.59 $ 8.68
Company average $ 11.17 $ 10.05 $ 10.28
------------------------------------------------------------------------------
NATURAL GAS ($/mcf) (1)
North America $ 0.71 $ 0.62 $ 0.57
North Sea $ 2.44 $ 2.07 $ 1.33
Offshore West Africa $ 1.05 $ 1.33 $ 1.39
Company average $ 0.73 $ 0.67 $ 0.60
------------------------------------------------------------------------------
COMPANY AVERAGE ($/boe) (1) $ 8.21 $ 7.35 $ 7.15
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
The Company continues to experience increasing production expense in 2006,
reflecting industry cost pressures in all of its operating areas.
54 Management's Discussion & Analysis
NORTH AMERICA
North America crude oil and NGLs production expense per bbl for the year ended
December 31, 2005 increased by 17% from 2004. The increase was primarily due
to higher industry wide service costs, higher fuel related expenses, and a
larger portion of the Company's crude oil volumes being comprised of higher
cost thermal crude oil in 2005 versus 2004, offset by the positive impact of
higher volumes relative to fixed costs.
North America natural gas production expense per mcf for the year ended
December 31, 2005 increased from the comparable periods in 2004. The increase
from 2004 was due to the service and commodity cost pressures previously
noted, offset by the positive impact of higher volumes relative to fixed
costs.
NORTH SEA
North Sea crude oil production expense varied on a per barrel basis from 2004
primarily due to the timing of maintenance work, the changes in production
volumes on a relatively fixed cost base, the timing of liftings from various
fields and the impact of production being diverted from the Kyle Field to the
Banff floating production storage and offtake vessel ("FPSO").
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expenses are largely fixed in nature
and fluctuated on a per barrel basis from 2004 due to changes in volumes.
Production expenses for the year ended December 31, 2005 compared to 2004 were
primarily impacted by the commencement of production from the Baobab Field in
August 2005.
MIDSTREAM
($ millions) 2005 2004 2003
------------------------------------------------------------------------------
Revenue $ 77 $ 68 $ 61
Production expense 24 20 15
------------------------------------------------------------------------------
Midstream cash flow 53 48 46
Depreciation 8 7 7
------------------------------------------------------------------------------
Segment earnings before taxes $ 45 $ 41 $ 39
==============================================================================
The Company's midstream assets consist of three crude oil pipeline systems and
a 50% working interest in an 84-megawatt cogeneration plant at Primrose.
Approximately 80% of the Company's heavy crude oil production is transported
to international mainline liquid pipelines via the 100% owned and operated
ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15%
owned Cold Lake Pipeline. The midstream pipeline assets allow the Company to
control the transport of its own production volumes as well as earn third
party revenue. This transportation control enhances the Company's ability to
manage the full range of costs associated with the development and marketing
of its heavier crude oil.
Earnings and cash flow attributable to midstream assets have increased
marginally from 2004 primarily due to increased heavy crude oil throughput
volumes and increased revenue from the Company's cogeneration plant.
DEPLETION, DEPRECIATION AND AMORTIZATION(1)
($ millions, except per boe amounts) (2) 2005 2004 2003
------------------------------------------------------------------------------
North America $ 1,595 $ 1,444 $ 1,209
North Sea 306 265 252
Offshore West Africa 104 53 41
------------------------------------------------------------------------------
Expense $ 2,005 $ 1,762 $ 1,502
$/boe $ 10.02 $ 9.37 $ 8.96
==============================================================================
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, Depreciation and Amortization ("DD&A") for the year ended December
31, 2005 increased in total and on a boe basis from 2004. The increase in DD&A
was due to higher finding and development costs associated with natural gas
exploration in North America, the fair value allocation of the acquisition
costs associated with acquisitions completed late in 2004, future abandonment
costs associated with the acquisition of additional properties in the North
Sea, higher estimated future costs to develop the Company's proved undeveloped
reserves in the North Sea and the commencement of production from the Baobab
Field in August 2005.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) (1) 2005 2004 2003
------------------------------------------------------------------------------
North America $ 34 $ 28 $ 26
North Sea 34 22 36
Offshore West Africa 1 1 --
------------------------------------------------------------------------------
Expense $ 69 $ 51 $ 62
$/boe $ 0.34 $ 0.27 $ 0.37
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Management's Discussion & Analysis 55
Accretion expense is the increase in the carrying amount of the asset
retirement obligations due to the passage of time. Asset retirement obligation
accretion expense for North America increased $6 million or 21% from 2004,
primarily due to increased activity in the conventional drilling program and
increased requirements under provincial reclamation legislation. Accretion
expense for the North Sea increased $12 million or 55% from 2004, largely due
to the impact of additional retirement obligations related to property
acquisitions completed late in 2004.
ADMINISTRATION EXPENSE
($ millions, except per boe amounts) (2) 2005 2004(1) 2003
------------------------------------------------------------------------------
Net expense $ 151 $ 125 $ 87
$/boe $ 0.75 $ 0.66 $ 0.52
==============================================================================
(1) Restated to conform to current year presentation.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Net administration expense for the year ended December 31, 2005 increased in
total and on a boe basis from the year ended December 31, 2004 primarily due
to higher staffing levels associated with the Company's expanding asset base
and costs associated with the Company's Share Bonus Plan.
The Share Bonus Plan incorporates employee share ownership in the Company
while reducing the granting of stock options and the dilution of current
Shareholders. Under the plan, cash bonuses awarded based on Company and
employee performance are subsequently used by a trustee to acquire common
shares of the Company. The common shares vest to the employee over a
three-year period provided the employee does not leave the employment of the
Company. If the employee leaves the employment of the Company, the unvested
common shares are forfeited under the terms of the plan. For the year ended
December 31, 2005, the Company recognized $17 million of compensation expense
under the Share Bonus Plan (December 31, 2004 - $10 million; 2003 - $nil).
STOCK-BASED COMPENSATION
($ millions) 2005 2004 2003
------------------------------------------------------------------------------
Stock-based compensation expense $ 723 $ 249 $ 200
==============================================================================
The Company's Stock Option Plan (the "Option Plan") provides current employees
(the "option holders") with the right to elect to receive common shares or a
direct cash payment in exchange for options surrendered. The design of the
Option Plan balances the need for a long-term compensation program to retain
employees with the benefits of reducing the impact of dilution on current
Shareholders and the reporting of the obligations associated with stock
options. Transparency of the cost of the Option Plan is increased since
changes in the intrinsic value of outstanding stock options are recognized
each period. The cash payment feature provides option holders with
substantially the same benefits and allows them to realize the value of their
options through a simplified administration process.
The Company recorded a $723 million ($481 million after tax) stock-based
compensation expense for the year ended December 31, 2005 in connection with
the 125% appreciation in the Company's share price (December 31, 2005 -
C$57.63; December 31, 2004 - C$25.63; December 31, 2003 - C$16.34; December
31, 2002 - C$11.70). As required by GAAP, the Company's outstanding stock
options are valued based on the difference between the exercise price of the
stock options and the market price of the Company's common shares, pursuant to
a graded vesting schedule. The liability is revalued quarterly to reflect
changes in the market price of the Company's common shares and the options
exercised or surrendered in the period, with the net change recognized in net
earnings, or capitalized during the construction period in the case of the
Horizon Project (2005 - $101 million; 2004 - $21 million; 2003 - $10 million).
The stock-based compensation liability reflects the Company's potential cash
liability should all the vested options be surrendered for a cash payout at
the market price on December 31, 2005. In periods when substantial stock price
changes occur, the Company is subject to significant earnings volatility.
For the year ended December 31, 2005, the Company paid $227 million for stock
options surrendered for cash settlement (December 31, 2004 - $80 million; 2003
- $31 million).
INTEREST EXPENSE
($ millions, except per boe amounts and interest rates)(1) 2005 2004 2003
-------------------------------------------------------------------------------
Interest expense $ 149 $ 189 $ 201
$/boe $ 0.74 $ 1.01 $ 1.20
Average effective interest rate 5.6% 5.2% 5.8%
===============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
56 Management's Discussion & Analysis
Net interest expense decreased on a total and boe basis for the year ended
December 31, 2005 from 2004 primarily due to the capitalization of
construction period interest related to the Horizon Project in 2005 of $72
million (2004 and 2003 - $nil). Pre-capitalization interest increased from
2004 mainly due to higher interest rates and carrying charges, offset by
decreased average debt levels and the impact of the strengthening Canadian
dollar, which decreased interest expense attributable to the Company's US
dollar denominated debt securities.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. These derivative
financial instruments are not used for trading or speculative purposes.
Changes in fair value of derivative financial instruments designated as hedges
are not recognized in net earnings until such time as the corresponding gains
or losses on the related hedged items are also recognized. Changes in fair
value of derivative financial instruments not designated as hedges are
recognized in the consolidated balance sheets each period with the offset
reflected in risk management activities in the statements of earnings.
The Company formally documents all hedging transactions at the inception of
the hedging relationship in accordance with the Company's risk management
policies. The effectiveness of the hedging relationship is evaluated both at
inception of the hedge and on an ongoing basis.
The Company enters into commodity price contracts to manage anticipated sales
of crude oil and natural gas production in order to protect cash flow for
capital expenditure programs. Gains or losses on these contracts are included
in risk management activities.
The Company enters into interest rate swap agreements to manage its fixed to
floating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amount on which the payments are based. Gains or losses on interest
rate swap contracts designated as hedges are included in interest expense.
Gains or losses on non-designated interest rate contracts are included in risk
management activities.
Cross currency swap agreements are periodically used to manage currency
exposure on US dollar denominated long-term debt. The cross currency swap
contracts require the periodic exchange of payments with the exchange at
maturity of notional principal amounts on which the payments are based. Gains
or losses on cross currency swap contracts designated as hedges are included
in interest expense.
Gains or losses on the termination of derivative financial instruments that
have been designated as hedges are deferred under other assets or liabilities
on the consolidated balance sheets and amortized into net earnings in the
period in which the underlying hedged transaction is recognized. In the event
a designated hedged item is sold, extinguished or matures prior to the
termination of the related derivative instrument, any unrealized derivative
gain or loss is recognized immediately in net earnings. Gains or losses on the
termination of financial instruments that have not been designated as hedges
are recognized in net earnings immediately.
($ millions) 2005 2004 2003
------------------------------------------------------------------------------
Realized loss (gain)
Crude oil and NGLs financial instruments $ 753 $ 501 $ 95
Natural gas financial instruments 283 5 88
Interest rate swaps (9) (32) (35)
------------------------------------------------------------------------------
$ 1,027 $ 474 $ 148
------------------------------------------------------------------------------
Unrealized loss (gain)
Crude oil and NGLs financial instruments $ 847 $ (47) $ --
Natural gas financial instruments 77 -- --
Interest rate swaps 1 7 --
------------------------------------------------------------------------------
$ 925 $ (40) $ --
------------------------------------------------------------------------------
Total $ 1,952 $ 434 $ 148
==============================================================================
The realized loss from crude oil and NGLs and natural gas financial
instruments decreased the Company's average realized prices as follows:
2005 2004 2003
------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)(1) $ 6.68 $ 4.85 $ 1.07
Natural gas ($/mcf)(1) $ 0.54 $ 0.01 $ 0.19
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volume.
Management's Discussion & Analysis 57
The realized gain on non-designated interest rate swaps would have decreased
the Company's reported interest expense as follows:
($ millions, except interest rates) 2005 2004 2003
------------------------------------------------------------------------------
Interest expense as reported $ 149 $ 189 $ 201
Less: realized risk management gain (9) (32) (35)
------------------------------------------------------------------------------
$ 140 $ 157 $ 166
Average effective interest rate 5.2% 4.4% 4.8%
==============================================================================
As effective as commodity hedges are against reference commodity prices, a
substantial portion of the derivative financial instruments entered into by
the Company do not meet the requirements for hedge accounting under GAAP due
to currency, product quality and location differentials (the "non-designated
hedges"). The Company is required to mark-to-market these non-designated
hedges based on prevailing forward commodity prices in effect at the end of
each reporting period. Accordingly, unrealized risk management expense
reflects, at the balance sheet date, the implied price differentials for the
non-designated hedges for future years. Due to the dramatic increase in crude
oil and natural gas forward pricing in 2005, the Company recorded a $925
million ($607 million after tax) unrealized loss on its risk management
activities for the year ended December 31, 2005 (2004 - a $40 million gain or
$27 million after tax; 2003 - $nil).
The cash settlement amount of the risk management financial derivative
instruments may vary materially depending upon the underlying crude oil and
natural gas prices at the time of final settlement of the financial derivative
instruments, as compared to their mark-to-market value at December 31, 2005.
In addition to the risk management liability recognized on the balance sheet
at December 31, 2005, the net unrecognized liability related to the fair value
of derivative financial instruments designated as hedges was $990 million
(December 31, 2004 - net unrecognized asset of $33 million).
Details relating to outstanding derivative financial instruments at December
31, 2005 are disclosed in note 10 to the Company's audited annual consolidated
financial statements as at December 31, 2005.
FOREIGN EXCHANGE
($ millions) 2005 2004 2003
------------------------------------------------------------------------------
Realized foreign exchange (gain) loss $ (29) $ 3 $ 8
Unrealized foreign exchange gain (103) (94) (343)
------------------------------------------------------------------------------
Total $(132) $ (91) $ (335)
==============================================================================
The Company's results are affected by the exchange rates between the Canadian
dollar, US dollar, and UK pound sterling. A majority of the Company's revenue
is based on reference to US dollar benchmark prices. An increase in the value
of the Canadian dollar in relation to the US dollar results in lower revenue
from the sale of the Company's production. Conversely a decrease in the value
of the Canadian dollar in relation to the US dollar will result in higher
revenue from the sale of the Company's production. Production expenses are
also subject to fluctuations due to changes in the exchange rate of the UK
pound sterling to the US dollar related to North Sea operations. The value of
the Company's US dollar denominated debt is also impacted by the value of the
Canadian dollar in relation to the US dollar.
In 2005, the majority of the realized foreign exchange gain was the result of
the repayment of the Company's US dollar preferred securities. In addition,
net foreign exchange gains were realized on foreign exchange rate fluctuations
on working capital items denominated in US dollars or UK pounds sterling. The
unrealized foreign exchange gain is related to the fluctuation of the Canadian
dollar in relation to the US dollar with respect to the US dollar debt and
working capital denominated in US dollars or UK pounds sterling. The Canadian
dollar ended the year at US$0.8577 compared to US$0.8308 at December 31, 2004
(2003 - US$0.7738).
In order to mitigate a portion of the volatility associated with fluctuations
in exchange rates, the Company has designated certain US dollar denominated
debt as a hedge against its net investment in US dollar based self-sustaining
foreign operations. Accordingly, translation gains and losses on this US
dollar denominated debt are included in the foreign currency translation
adjustment in Shareholders' equity in the consolidated balance sheets.
58 Management's Discussion & Analysis
TAXES
($ millions, except income tax rates) 2005 2004 2003
------------------------------------------------------------------------------
Taxes other than income tax
Current $ 203 $ 210 $ 116
Deferred (9) (45) (9)
------------------------------------------------------------------------------
Total $ 194 $ 165 $ 107
==============================================================================
Current income tax
North America - Current income tax $ 82 $ 89 $ 43
North America - Large Corporations Tax 16 11 16
North Sea 155 2 23
Offshore West Africa 32 13 10
Other 1 1 --
------------------------------------------------------------------------------
Total $ 286 $ 116 $ 92
==============================================================================
Future income tax $ 353 $ 474 $ 338
Effective income tax rate 37.8% 29.6% 23.5%
==============================================================================
Taxes other than income tax includes current and deferred petroleum revenue
tax ("PRT") and Canadian provincial capital taxes and surcharges. PRT is
charged on certain fields in the North Sea at the rate of 50% of net operating
income, after allowing for certain deductions including abandonment
expenditures.
Taxable income from the conventional crude oil and natural gas business in
Canada is generated by partnerships, with the related income taxes payable in
a subsequent year. North America current income taxes have been provided on
the basis of the corporate structure and available income tax deductions and
will vary upon the nature and amount of capital expenditures incurred in
Canada.
The North Sea current income tax expense for 2005 increased from 2004 due
mainly to higher realized product prices, increased sales volumes and the
deductibility in 2004 of the cost of assets acquired in the UK. In December
2005, the UK government announced plans to double the supplementary charge on
profits from UK North Sea crude oil and natural gas production to 20%. If
enacted, the increased North Sea supplementary charge would increase the
Company's income tax rate in the North Sea from 40% to 50%. The supplementary
charge excludes any deduction for financing costs. A charge has not been
reflected in 2005 net earnings as the proposed change has not been
substantively enacted. If enacted in 2006, the Company anticipates that this
rate change will result in a charge to future income taxes in the amount of
$111 million.
During 2005, the province of British Columbia enacted legislation to reduce
its corporate income tax rate by 1.5% effective July 1, 2005. As a result, the
North America future income tax liability was reduced by $19 million. In 2004,
the North America future tax liability was reduced by $66 million as a result
of a reduction in the Alberta corporate income tax rate from 12.5% to 11.5%.
In 2003, the Federal Government enacted legislation to reduce the corporate
income tax rate on income from resource activities over a five-year period
starting January 1, 2003, bringing the resource industry in line with the
general corporate income tax rate. As part of the corporate income tax rate
reduction, the legislation also provides for the phased elimination of the
existing 25% resource allowance and the introduction of a deduction for actual
provincial and other crown royalties paid.
The following table shows the effect of non-recurring benefits on income
taxes:
($ millions, except income tax rates) 2005 2004 2003
------------------------------------------------------------------------------
Income tax as reported
Current income tax $ 286 $ 116 $ 92
Future income tax expense 353 474 338
------------------------------------------------------------------------------
639 590 430
Provincial corporate tax rate reductions 19 66 31
Federal corporate tax rate reductions -- -- 247
------------------------------------------------------------------------------
Total $ 658 $ 656 $ 708
Expected effective income tax rate
before non-recurring benefits 39.0% 32.9% 38.6%
==============================================================================
The effective income tax rate for 2005 increased over 2004 due to the effects
of the phased elimination of the resource allowance and the phased
deductibility of crown royalties. It is anticipated that in 2006, based on
budgeted prices and the current availability of tax pools, the Company is
expected to be cash taxable in Canada in the amount of $110 million to $170
million.
Management's Discussion & Analysis 59
CAPITAL EXPENDITURES (1)
($ millions) 2005 2004 2003
------------------------------------------------------------------------------
Expenditures on property, plant and equipment
Net property acquisitions (2) $ (320) $ 1,835 $ 336
Land acquisition and retention 254 120 154
Seismic evaluations 132 89 77
Well drilling, completion and equipping 2,000 1,394 1,194
Pipeline and production facilities 1,295 821 522
------------------------------------------------------------------------------
Total net reserve replacement expenditures 3,361 4,259 2,283
------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 1,329 -- --
Capitalized interest and other 170 291 152
------------------------------------------------------------------------------
Total Horizon Project 1,499 291 152
------------------------------------------------------------------------------
Midstream 4 16 11
Abandonments (3) 46 32 40
Head office 22 35 20
------------------------------------------------------------------------------
Total net capital expenditures $ 4,932 $ 4,633 $ 2,506
------------------------------------------------------------------------------
By segment
------------------------------------------------------------------------------
North America $ 2,530 $ 3,355 $ 1,769
North Sea 387 608 338
Offshore West Africa 439 295 176
Other 5 1 --
Horizon Project 1,499 291 152
Midstream 4 16 11
Abandonments (3) 46 32 40
Head office 22 35 20
------------------------------------------------------------------------------
Total $ 4,932 $ 4,633 $ 2,506
==============================================================================
(1) The net capital expenditures do not include non-cash property, plant and
equipment additions or disposals.
(2) Includes Business Combinations. The 2004 comparative figure includes $26
million in non-cash consideration.
(3) Abandonments represent expenditures to settle asset retirement obligations
and have been reflected as capital expenditures in this table.
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company focuses its activities in core regions where it can dominate the
land base and infrastructure. The Company focuses on maintaining its land
inventories to enable the continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By dominating
infrastructure, the Company is able to maximize utilization of its production
facilities, thereby increasing control over production costs.
Net capital expenditures for the year ended December 31, 2005 were $4,932
million compared to $4,633 million for the year ended December 31, 2004 (2003
- $2,506 million). During 2005, the Company continued to make significant
progress on its larger, future-growth projects, most notably the Horizon
Project, while maintaining its focus on existing assets. The Company drilled a
total of 1,882 net wells in 2005 consisting of 890 natural gas wells, 627
crude oil wells, 248 stratigraphic test and service wells, and 117 wells that
were dry. This compared to 1,449 net wells drilled in 2004 (2003 - 1,793 net
wells). The Company achieved an overall success rate of 93%, excluding
stratigraphic test and service wells (2004 and 2003 - 91%).
NORTH AMERICA
North America accounted for approximately 83% of the total capital
expenditures for the year ended December 31, 2005 compared to approximately
80% in 2004 (2003 - 79%).
During 2005, the Company drilled 975 net wells targeting natural gas,
including 228 wells in Northeast British Columbia, 238 wells in the Northern
Plains region, 166 wells in Northwest Alberta, and 343 wells in the Southern
Plains region. The Company also drilled 642 net wells targeting crude oil
during 2005. The majority of these wells were concentrated in the Company's
crude oil Northern Plains region where 360 heavy crude oil wells, 84 Pelican
Lake crude oil wells, 109 thermal crude oil wells, and 7 light crude oil wells
were drilled. Another 82 light crude oil wells were drilled during the year in
the Company's other regions.
As part of the development of the Company's heavy crude oil resources, the
Company is continuing with its Primrose thermal projects, which includes the
Primrose North expansion project and drilling additional wells in the Primrose
South project to augment existing production. The Primrose North expansion was
substantially completed in 2005 with total capital expenditures of
approximately $300 million incurred. Initial steaming commenced in November
2005 and first crude oil production began in January 2006.
60 Management's Discussion & Analysis
In 2004, the Company filed a public disclosure document for regulatory
approval of its Primrose East project, a new facility located about 15
kilometers from its existing Primrose South steam plant and 25 kilometers from
its Wolf Lake central processing facility. The development application was
submitted to the Alberta Energy and Utilities Board in January 2006, with
potential impacts associated with the use of bitumen as fuel being evaluated
in the Environmental Impact Assessment. The Company expects construction to
begin in 2007, with initial steaming scheduled for January 2009.
Development at Pelican Lake continued on track in 2005, with 84 wells being
drilled and production increasing from approximately 18,000 bbl/d to
approximately 28,000 bbl/d over the course of the year. The waterflood
conversion project is on schedule with production response exceeding
expectations. The Company plans to enhance the waterflood process through
utilization of Polymer Flood technology. A Polymer Flood pilot has been in
operation since May 2005 with positive results. The drilling of 150 horizontal
wells is planned for 2006.
During 2005, the Company sold a large portion of its overriding royalty
interests on various producing properties throughout Western Canada and
Ontario that were considered non-core to its operations, for proceeds of
approximately $345 million, after giving effect to anticipated adjustments.
Above average temperatures have continued into 2006. Accordingly, the Company
is leveraging its deep drilling inventory and optimizing drilling plans to
adjust for road bans and/or site access issues. Despite these challenges the
Company still expects to complete the majority of its winter drilling program.
However, the risk remains for an early spring breakup which could
significantly delay tie-ins of many of these new wells. In 2006, the Company's
overall drilling activity in North America is expected to be comprised of
approximately 1,139 net natural gas wells and 697 net crude oil wells
excluding stratigraphic test/service wells.
HORIZON PROJECT
On February 9, 2005 the Board of Directors of the Company unanimously approved
the Company to proceed with Phase 1 of the Horizon Project.
The Horizon Project has continued on schedule and on budget. Specifically, as
at December 31, 2005:
o Phase 1 Horizon Project construction was 19% complete;
o The detailed engineering work was on schedule, with 3-D engineering
models progressing as planned;
o The Company awarded $3.8 billion of contracts and purchase orders,
with a further $600 million in various stages of the tender process;
and
o Approximately 1,700 people were on site and functional.
Major activities for 2006 will include:
o Substantial completion of detailed engineering;
o Completion and setting of main piperack modules;
o Receiving and erecting of critical equipment;
o Beginning construction of ore preparation plant; and
o Substantial completion of foundations in each area.
First production of light, sweet Synthetic Crude Oil from Phase 1 construction
is targeted to commence in the second half of 2008. The Horizon Project is in
the early stages of construction.
NORTH SEA
The Company continued in 2005 with its planned program of infill drilling,
recompletions, workovers and waterflood optimizations. During 2005, 14 net
wells were drilled, consisting of 12 net crude oil wells, 1 net dry well and 1
net service well, with an additional 2.9 net wells drilling at quarter-end.
In anticipation of the 2005 program of infill drilling, workovers, and third
party business on the T and B Blocks, the Company completed a major
refurbishment of the Tiffany platform drilling rig, which is facilitating a
two-well program targeting unswept areas of the field. The first of these two
wells was drilled and completed late in 2005.
Production from the Kyle Field was diverted to the Banff FPSO during 2005.
Under the terms of an early termination agreement, the existing Kyle FPSO was
released in September 2005. The consolidation of these production facilities
is expected to result in lower combined operating costs from these fields and
may ultimately extend field lives for both fields.
Management's Discussion & Analysis 61
OFFSHORE WEST AFRICA
Offshore West Africa capital expenditures include the development of the
57.61% owned and operated Baobab Field, which commenced production on August
9, 2005 at approximately 30,000 bbl/d net to the Company. Upon completion of
drilling additional wells in 2006, production levels are expected to achieve
approximately 35,000 bbl/d net to the Company.
In East Espoir, two of the four infill wells scheduled for drilling were
completed during 2005, with the remainder expected to be completed in 2006.
The drilling of these wells was a result of additional testing and evaluation
that revealed a larger quantity of crude oil in place, based upon reservoir
studies and production history to date. These new producer wells will
effectively exploit this additional potential and could increase the
recoverable resources and production. The West Espoir drilling tower, which
will facilitate development drilling of the reservoir, is on site and was
installed in late 2005. This project is progressing on time and on budget with
first crude oil expected in 2006, increasing to approximately 13,000 boe/d
once fully developed.
The Company purchased a 100% operator interest in the Olowi PSC offshore Gabon
in October 2005 and received approval of its development plan for this
acquisition subsequent to year end. Development plans include a FPSO handling
input from two or three shallow-water producing platforms. Development is
expected to begin late in 2006, with first oil expected late in 2008 at a rate
of approximately 20,000 bbl/d.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2005 2004 2003
------------------------------------------------------------------------------
Working capital deficit (1) $ 1,774 $ 652 $ 505
Long-term debt $ 3,321 $ 3,538 $ 2,748
------------------------------------------------------------------------------
Shareholders' equity
Share capital $ 2,442 $ 2,408 $ 2,353
Retained earnings 5,804 4,922 3,650
Foreign currency translation adjustment (9) (6) 3
------------------------------------------------------------------------------
Total $ 8,237 $ 7,324 $ 6,006
==============================================================================
Debt to cash flow (2) 0.7x l.0x 0.9x
Debt to EBITDA (3) 0.6x 0.9x 0.8x
Debt to book capitalization (4) 28.7% 33.8% 32.8%
Debt to market capitalization 9.7% 21.4% 25.1%
After tax return on average common
shareholders' equity (5) 14.3% 21.4% 25.6%
After tax return on average capital
employed (6) 10.4% 15.3% 17.1%
==============================================================================
(1) Calculated as current assets less current liabilities.
(2) Calculated as current and long-term debt; divided by cash flow from
operations for the year.
(3) Calculated as current and long-term debt; divided by earnings before
interest, taxes, depreciation, depletion and amortization, asset
retirement obligation accretion, unrealized foreign exchange, stock-based
compensation expense and unrealized risk management activities for the
year.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as net earnings for the year as a percentage of average common
shareholders' equity for the period.
(6) Calculated as net earnings plus after-tax interest expense for the year;
as a percentage of average capital employed. Average capital employed is
the average shareholders' equity and current and long-term debt for the
year.
The Company's capital resources at December 31, 2005 consist primarily of cash
flow from operations and available credit facilities. Cash flow from
operations is dependent on factors discussed in the Risks and Uncertainties
section of this MD&A. The Company's ability to renew existing credit
facilities and raise new debt is dependent upon these factors, maintaining an
investment grade debt rating and the condition of capital and credit markets.
Management believes internally generated cash flows supported by the
implementation of the Company's hedge policy, the flexibility of its capital
expenditure programs supported by its five and ten year financial plans, the
Company's existing credit facilities and the Company's ability to raise new
debt, will be sufficient to sustain its operations and support its growth
strategy.
At December 31, 2005 the Company had undrawn bank lines of credit of $3,285
million. These credit lines are supported by credit facilities, which if not
extended, mature in 2008, 2009 and 2010.
At December 31, 2005, the Company's working capital deficit was $1,774 million
and included the current portion of other long-term liabilities of $1,471
million, comprised of stock-based compensation of $629 million and the
mark-to-market valuation of non-designated risk management financial
derivative instruments of $842 million. The settlement of the stock-based
compensation liability is dependant upon both the surrender of vested stock
options for cash settlement by employees and the value of the Company's share
price at the time of surrender. The cash settlement amount of the risk
management financial derivative instruments may vary materially depending upon
the underlying crude oil and natural gas prices at the time of final
settlement of the financial derivative instruments, as compared to their
mark-to-market value at December 31, 2005.
The Company is committed to maintaining a strong financial position. In 2005,
strong operational results and high commodity prices resulted in debt to book
capitalization levels of 28.7%. The Company believes it has the necessary
financial capacity to complete the
62 Management's Discussion & Analysis
Horizon Project while at the same time not compromising delivery of
conventional crude oil and natural gas growth opportunities. The financing of
Phase 1 of the Horizon Project development is guided by the competing
principles of retaining as much direct ownership interest as possible while
maintaining a strong balance sheet. Existing proved development projects,
which have largely been funded prior to December 31, 2005, such as Baobab,
Primrose North and West Espoir should provide identified growth in production
volumes in 2006 through 2008, and are expected to generate incremental free
cash flows during this period.
In January 2005, the Board of Directors authorized the expansion of the
Company's commodity hedging program to reduce the risk of volatility in
commodity price markets and to underpin the Company's cash flow for its
capital expenditures program through the Horizon Project construction period.
This expanded program allows for the hedging of up to 75% of the near 12
months budgeted production, up to 50% of the following 13 to 24 months
estimated production and up to 25% of production expected in months 25 to 48
through the use of derivative financial instruments. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. As a result, approximately 75% of budgeted 2006 crude oil volumes
have been hedged through the use of collars. Approximately 60% of budgeted
2006 natural gas volumes have similarly been hedged through the use of
collars. In addition, for 2007, put options have been acquired on 200,000
bbl/d at an average floor price of US$47.50 and a further 100,000 bbl/d at an
average floor price of US$28.00. The Company has not hedged any production
volumes beyond 2007. The Company continues to evaluate the need for further
hedging in 2007 and beyond, given continuing capital requirements for Horizon
and other capital projects.
LONG-TERM DEBT
Long-term debt at December 31, 2005 amounted to $3,321 million. The debt to
EBITDA ratio decreased to 0.6x and the debt to book capitalization decreased
to 28.7% compared to a debt to EBITDA ratio of 0.9x and a debt to book
capitalization of 33.8% in 2004. These ratios are currently below the
Company's guidelines for balance sheet management of debt to EBITDA of 1.5x to
2.0x and debt to book capitalization of 35% to 45%.
OPERATING FACILITIES
As at December 31, 2005 the Company had in place unsecured syndicated bank
credit facilities of $3,425 million, comprised of:
o a $100 million operating demand facility;
o a two-tranche revolving credit and term loan facility of $1,825
million; and
o a 5-year revolving and term loan facility of $1,500 million.
The first $1,000 million tranche of the $1,825 million facility is fully
revolving for a period of three years to June 2008. The second tranche of $825
million is fully revolving for a period of five years to June 2010. Both
tranches are extendible annually for one-year periods at the mutual agreement
of the Company and the lenders. If not extended, the full amount of the
outstanding principal would be repayable at the end of year two following the
initiation of the term period. The $1,500 million revolving credit and term
loan facility has a five-year term, with three, one-year extension provisions.
If the facility is not extended, the amount outstanding would be repayable in
December 2009. These facilities provide that the borrowings may be made by way
of operating advances, prime loans, bankers' acceptances, US base rate loans
or US dollar LIBOR advances, which bear interest at the bank's prime rates or
at money market rates plus applicable margins.
The weighted average interest rate of the bank credit facilities outstanding
at December 31, 2005, was 5.44% (2004 - 3.47%).
The Company also has an unsecured (pound)15 million demand overdraft credit
facility for the Company's North Sea operations. At December 31, 2005 there
were no amounts drawn on this facility.
In addition to the outstanding debt, as at December 31, 2005 letters of credit
aggregating $24 million have been issued.
MEDIUM-TERM NOTES
In May 2005, the Company issued $400 million of debt securities maturing June
2015, bearing interest at 4.95%. Proceeds from the securities issued were used
to repay bankers' acceptances under the Company's bank credit facilities.
In May 2004, the Company repaid the $125 million 6.85% unsecured debentures
due May 2004, which were issued under a previous medium-term note program.
In January 2006, the Company issued $400 million of debt securities maturing
January 2013, bearing interest at 4.50%. Proceeds from the securities issued
were used to repay bankers' acceptances under the Company's bank credit
facilities. After issuing these securities, the Company has $1.6 billion
remaining on its $2 billion shelf prospectus filed in August 2005 that allows
for the issue of medium-term notes in Canada until September 2007. If issued,
these securities will bear interest as determined at the date of issuance.
Management's Discussion & Analysis 63
SENIOR UNSECURED NOTES
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes. The 6.42% senior unsecured notes were repaid in May 2004.
The adjustable rate senior unsecured notes bear interest at 6.54% and have
annual principal repayments of US$31 million commencing in May 2007, through
May 2009.
PREFERRED SECURITIES
In September 2005, the Company redeemed the US$80 million 8.30% preferred
securities due May 25, 2011 for cash consideration of US$91 million, including
an early repayment premium of US$11 million as required under the Note
Purchase Agreement.
US DOLLAR DEBT SECURITIES
In June 2005, the Company filed a short form shelf prospectus that allows for
the issue of up to US$2 billion of debt securities in the United States until
July 2007. If issued, these securities will bear interest as determined at the
date of issuance.
In December 2004, the Company issued US$350 million of debt securities
maturing December 2014, bearing interest at 4.90% and US$350 million of debt
securities maturing February 2035, bearing interest at 5.85%. Proceeds from
the securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities. The Company has entered into interest rate
swap contracts to convert the fixed rate interest coupon into a floating
interest rate on the securities due December 2014.
The ratings of the Company's debt securities and its relationships with
principal banks are important to the Company as it continues to expand and
grow. Hence, it is the Company's management intention to maintain a strong
balance sheet and financial position. The Company's debt securities are rated
"Baa1" with a stable outlook by Moody's Investor Services Inc., "BBB+" by
Standard & Poors Corporation ("S&P") and "BBB(high)" with a stable trend by
Dominion Bond Rating Services Limited. S&P assigns a rating outlook to the
Company and not to the individual debt instruments. S&P has assigned a
negative outlook to the Company.
SHARE CAPITAL
Shareholders of the Company approved a subdivision or share split of its
issued and outstanding common shares on a two-for-one basis at the Company's
Annual and Special Meeting held on May 5, 2005. As at December 31, 2005, there
were 536,348,000 common shares outstanding. As at February 21, 2006, the
Company had 537,156,000 common shares outstanding.
In January 2005, the Company renewed its Normal Course Issuer Bid allowing it
to purchase up to 26,818,012 common shares or 5% of the Company's outstanding
common shares on the date of announcement, during the 12-month period
beginning January 24, 2005 and ending January 23, 2006. As at December 31,
2005, the Company had purchased 850,000 common shares at an average price of
$53.29 per common share for a total cost of $45 million.
In January 2006, the Company announced the renewal of its Normal Course Issuer
Bid through the facilities of the Toronto Stock Exchange and the New York
Stock Exchange to purchase up to 26,852,545 common shares or 5% of the
outstanding common shares of the Company on the date of the announcement,
during the 12-month period beginning January 24, 2006 and ending January 23,
2007. As at February 21, 2006, the Company had not purchased any additional
shares under the Normal Course Issuer Bid.
In February 2005, the Board of Directors approved an increase in the annual
dividend paid by the Company to $0.225 per common share. In May 2005, the
Board of Directors approved an increase in the annual dividend paid by the
Company to $0.24 per common share. In February 2004, the Board of Directors
increased the annual dividend paid by the Company to $0.20 per common share,
up from the previous level of $0.15 per common share.
In February 2006, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.30 per common share for 2006. The
increase represents a 27% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the sixth consecutive year in which the Company has paid dividends and
the fifth consecutive year of an increase in the distribution paid to its
Shareholders.
64 Management's Discussion & Analysis
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
contractual arrangements and commitments that will have an impact on the
Company's future operations. These contractual obligations and commitments
primarily relate to debt repayments, operating leases relating to office space
and offshore production and storage vessels, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to asset retirement obligations. The Company has not entered into any
contracts that would require consolidation under CICA Accounting Handbook,
AcG-15, Consolidation of Variable Interest Entities. The following table
summarizes the Company's commitments as at December 31, 2005:
($ millions) 2006 2007 2008 2009 2010 Thereafter
--------------------------------------------------------------------------------------------------------
Product transportation and
pipeline (1) $ 195 $ 133 $ 148 $ 94 $ 85 $ 1,111
Offshore equipment operating
lease $ 51 $ 51 $ 52 $ 51 $ 51 $ 180
Offshore drilling $ 132 $ 100 $ 35 $ -- $ -- $ --
Asset retirement obligations (2) $ 82 $ 4 $ 4 $ 4 $ 7 $ 3,224
Long-term debt (3) $ -- $ 161 $ 36 $ 36 $ -- $ 2,966
Other (4) $ 61 $ 62 $ 21 $ 29 $ 23 $ 8
========================================================================================================
(1) During the year, the Company entered into a 25 year pipeline
transportation agreement commencing in 2008, related to future crude oil
production. The agreement is renewable for successive 10-year periods at
the Company's option. During the initial term, annual toll payments before
operating costs will be approximately $35 million.
(2) Represents management's estimate of the future payments to settle asset
retirement obligations related to resource properties, facilities,
production platforms and gathering systems, based on current legislation
and industry operating practices.
(3) No debt repayments are reflected for the bank credit facilities due to the
extendable nature of the facilities.
(4) Consists of future expenditures related primarily to office lease,
electricity and crude oil processing.
The Board of Directors has approved the construction costs for Phase 1 of the
Horizon Project, which are budgeted to be $6.8 billion, including a
contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6
billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and
2008.
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect
on its consolidated financial position.
RESERVES
For the year ended December 31, 2005, the Company retained qualified
independent reserve evaluators, Sproule Associates Limited ("Sproule") and
Ryder Scott Company ("Ryder Scott") to evaluate 100% of the Company's
conventional proved and probable crude oil, natural gas liquids ("NGL") and
natural gas reserves (1) and prepare Evaluation Reports on these reserves.
Sproule evaluated the Company's North America conventional assets and Ryder
Scott evaluated its international conventional assets. The Company 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. There are two principal
differences between the two standards. The first is the additional requirement
under NI 51-101 to disclose both proved, and proved and probable reserves, as
well as the related net present value of future net revenues using forecast
prices and costs. The second is in the definition of proved reserves; however,
as discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the
standards that NI 51-101 employs, the difference in estimated proved reserves
based on constant pricing and costs between the two standards is not material.
The Company has disclosed proved conventional reserves and the Standardized
Measure of discounted future net cash flows using year-end constant prices and
costs as mandated by the SEC in the supplementary oil and gas information
section of this Annual Report. The Company has elected to provide the net
present value (2) of these same conventional proved reserves as well as the
conventional proved and probable reserves and the net present value of these
reserves under the same parameters as additional voluntary information. The
Company has also elected to provide both proved, and proved and probable
conventional reserves and the net present value of these reserves using
forecast prices and costs as voluntary additional information, which is
disclosed in the Company's most recent Annual Information Form.
Reserves and net present 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.
For the year ended December 31, 2005, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants ("GLJ"), to evaluate
100% of Phases 1 through 3 of the Company's Horizon Project and prepare an
Evaluation Report on the Company's proved and probable oil sands mining
reserves incorporating both the mining and upgrading projects. These reserves
were evaluated adhering to the requirements of SEC Industry Guide 7 using
year-end constant pricing and have been disclosed separately from the
Company's conventional proved and probable crude oil, NGL and natural gas
reserves.
Management's Discussion & Analysis 65
The Reserve Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with each of Sproule, Ryder
Scott and GLJ to review the qualifications of and procedures used by each
evaluator in determining the estimate of the Company's quantities and net
present value of remaining conventional crude oil, NGL and natural gas
reserves as well as the Company's quantity of oil sands mining reserves.
Additional reserve disclosure is contained in the supplementary oil and gas
information of this Annual Report and the Company's most recent Annual
Information Form.
(1) Conventional crude oil, NGL and natural gas includes all of the Company's
light and medium, heavy, and thermal crude oil, natural gas, coal bed
methane and natural gas liquid activities. It does not include the
Company's oil sands mining assets.
(2) Net present values of conventional reserves are based upon discounted cash
flows prior to the consideration of income taxes and existing asset
abandonment liabilities. Only future development costs and associated
material well abandonment liabilities have been applied with the exception
of Offshore West Africa where all abandonment liabilities have been
included.
RISKS AND UNCERTAINTIES
The Company is exposed to various operational risks inherent in exploring,
developing, producing and marketing crude oil and natural gas and the mining
and upgrading of bitumen. These inherent risks include, but are not limited
to, the following items:
o Economic risk of finding and producing reserves at a reasonable cost,
including the risk of reserve revisions due to economic and technical
factors. Reserve revisions can have a positive or negative impact on
asset valuations and depletion rates.
o Pricing risk of marketing reserves at an acceptable price given
current market conditions.
o Regulatory risk related to approval for exploration and development
activities, which can add to costs or cause delays in projects.
o Labour risk associated with securing the manpower necessary to
complete capital projects in a timely and cost effective manner.
o Credit risk related to non-payment for sales contracts or
non-performance by counterparties to contracts.
o Interest rate risk associated with the Company's ability to secure
financing at commercially acceptable terms.
o Foreign exchange risk due to fluctuating exchange rates, as the
majority of sales are based in US dollars.
o Environmental impact risk associated with exploration and development
activities.
o Risk of catastrophic loss due to fire, explosion or acts of nature.
o Other risks associated with changing governmental policies, social
instability and other political, economic or diplomatic developments
in the Company's international operations.
The Company uses a variety of means to help minimize these risks. The Company
maintains a comprehensive insurance program to reduce risk to an acceptable
level and to protect it against significant losses. Operational control is
enhanced by focusing efforts on large core regions with high working interests
and by assuming operatorship of all key facilities. Product mix is
diversified, ranging from the production of natural gas to the production of
crude oil of various grades. The Company believes this diversification reduces
price risk when compared with over-leverage to one commodity. Sales of crude
oil and natural gas are aimed at various markets to ensure that undue exposure
to any one market does not exist. Financial instruments are utilized to help
ensure targets are met and to manage commodity prices, foreign currency rates
and interest rate exposure. The Company minimizes credit risks by entering
into sales contracts and financial derivatives with only highly rated entities
and financial institutions. The arrangements and policies concerning the
Company's financial instruments are under constant review and may change
depending upon the prevailing market conditions. Refer to the "Risk management
activities" section of this MD&A. In addition, the Company reviews its
exposure to individual companies on a regular basis, and where appropriate
ensures that parental guarantees or letters of credit are in place to minimize
the impact in the event of default.
The Company's capital structure mix is also monitored on a continual basis to
ensure that it optimizes flexibility, minimizes cost and offers the greatest
opportunity for growth. This includes the determination of a reasonable level
of debt and any interest rate exposure risk that may exist.
For additional detail regarding the Company's risks and uncertainties, refer
to the Company's most recent Annual Information Form.
66 Management's Discussion & Analysis
ENVIRONMENT
The Company continues to employ an Environmental Management Plan (the "Plan")
to ensure the welfare of its employees, the communities in which it operates,
and the environment as a whole. Environmental protection is of fundamental
importance and is undertaken in accordance with guiding principles approved by
the Company's Board of Directors. A detailed copy of the Company's Plan is
presented to, and reviewed by, the Board of Directors annually. The Plan is
updated quarterly at the Directors' meetings.
The Company's environmental management plan and operating guidelines focus on
minimizing the impact of field operations while meeting regulatory
requirements and corporate standards. The Company, as part of this plan, has
implemented a proactive program that includes:
o An annual internal environmental compliance audit and inspection
program of the Company's operating facilities;
o A suspended well inspection program to support future development or
eventual abandonment;
o Appropriate reclamation and decommissioning standards for wells and
facilities ready for abandonment;
o An effective surface reclamation program;
o A due diligence program related to groundwater monitoring;
o An active program related to preventing and reclaiming spill sites;
o A solution gas reduction and conservation program; and
o A program to replace the majority of fresh water for steaming with
brackish water.
The Company has also established stringent operating standards in four areas:
o Using water-based, environmentally friendly drilling muds whenever
possible;
o Implementing cost effective ways of reducing greenhouse natural gas
emissions per unit of production;
o Exercising care with respect to all waste produced through effective
waste management plans; and
o Minimizing produced water volumes onshore and offshore through
cost-effective measures.
In 2005, the Company's capital expenditures included $46 million for
abandonment expenditures, an increase from $32 million in 2004 (2003 - $40
million).
Estimated asset retirement obligation,
undiscontinued ($ millions) 2005 2004
------------------------------------------------------------------------------
North America $ 2,050 $ 1,770
North Sea 1,185 1,265
Offshore West Africa 90 25
------------------------------------------------------------------------------
3,325 3,060
North Sea PRT recovery (370) (600)
------------------------------------------------------------------------------
$ 2,955 $ 2,460
==============================================================================
The estimate of the future site restoration liability is based on estimates of
future costs to abandon and restore the wells, production facilities and
offshore production platforms. There are numerous factors that affect these
costs including such things as the number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on
engineering estimates using current costs and technology in accordance with
present legislation and industry operating practice. The future abandonment
costs to be incurred by the Company in the North Sea will result in an
estimated recovery of PRT of $370 million (2004 - $600 million, 2003 - $330
million), as abandonment costs are an allowable deduction in determining PRT
and may be carried back to reclaim PRT previously paid. The PRT recovery
reduces the net abandonment liability of the Company to $2,955 million (2004 -
$2,460 million, 2003 - $1,950 million). The North Sea PRT recovery has
decreased substantially from 2004 primarily due to improved economics related
to the various fields, including a higher pricing environment and stronger
Canadian dollar at December 31, 2005. Under these economic conditions, end of
field losses at Tiffany previously assumed to be available for relief against
PRT due from other fields is significantly reduced. The Company's strategy in
the North Sea consists of developing commercial hubs around its core operated
properties with the goal of increasing production, lowering costs and
extending the economic lives of its production facilities, thereby delaying
the eventual abandonment dates.
KYOTO PROTOCOL
In December 2002, the Canadian Federal Government ratified the Kyoto Protocol
("Kyoto"). The Company continues to work with the Federal and Provincial
governments on the regulatory framework for greenhouse gases for larger
emitters. The framework under development would see harmonized regulation
between the two levels of government. Both levels of government have indicated
that existing legislation will be amended in 2006 to create further
requirements for reporting emissions, facility-based emission intensity
targets and regulatory compliance. Compliance with emission intensity targets
is expected for 2008, which is the first year of the compliance period for the
Kyoto Protocol.
Management's Discussion & Analysis 67
The Company will continue to develop strategies that will enable it to deal
with the risks and opportunities associated with new climate change policies.
In addition, the Company will work with relevant parties to ensure that new
policies encourage innovation, energy efficiency, targeted research and
development while not impacting Canada's competitive position.
Due to the high degree of cost uncertainty when the Federal Government
ratified Kyoto, maximum per tonne cost assurances were agreed with large
emitters for 2008 - 2012. Beyond 2012 investment concerns were addressed by
the Federal Government as outlined in eight principles that would guide its
negotiations and policies for this later stage.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of generally accepted
accounting principles that have a significant impact on the Company's
financial position and operations. Actual results could differ from those
estimates, and those differences could be material. Critical accounting
estimates are reviewed by the Company's Audit Committee annually. The Company
believes the following are the most critical accounting estimates in preparing
its consolidated financial statements.
PROPERTY, PLANT AND EQUIPMENT/DEPLETION, DEPRECIATION AND AMORTIZATION
The Company follows the full cost method of accounting for its conventional
crude oil and natural gas properties and equipment. Accordingly, all costs
relating to the exploration for and development of conventional crude oil and
natural gas reserves, whether successful or not, are capitalized and
accumulated in country-by-country cost centres. Proceeds on disposal of
properties are ordinarily deducted from such costs without recognition of
profit or loss except where such disposal constitutes a significant portion of
the Company's reserves in that country. Under Canadian GAAP, the capitalized
costs and future capital costs related to each cost centre from which there is
production are depleted on the unit-of-production method based on the
estimated proved reserves of that country using estimated future prices and
costs, rather than constant dollar pricing as required by the SEC. The
carrying amount of crude oil and natural gas properties in each cost centre
may not exceed their recoverable amount ("the ceiling test"). The recoverable
amount is calculated as the undiscounted cash flow using proved reserves and
estimated future prices and costs. If the carrying amount of a cost centre
exceeds its recoverable amount, an impairment loss equal to the amount by
which the carrying amount of the properties exceeds their estimated fair value
is charged against net earnings. Fair value is calculated as the cash flow
from those properties using proved and probable reserves and estimated future
prices and costs, discounted at a risk-free interest rate.
The alternate acceptable method of accounting for crude oil and natural gas
properties and equipment is the successful efforts method. A major difference
in applying the successful efforts method is that exploratory dry holes and
geological and geophysical exploration costs would be charged against net
earnings in the year incurred rather than being capitalized to property, plant
and equipment. In addition, under this method cost centres are defined based
on reserve pools rather than by country.
The use of the full cost method usually results in higher capitalized costs
and higher DD&A rates compared to the successful efforts method.
CRUDE OIL AND NATURAL GAS RESERVES
The Company retains qualified independent reserves evaluators to evaluate the
Company's proved and probable crude oil and natural gas reserves. In 2005,
100% of the Company's reserves were evaluated by qualified independent
reserves evaluators.
The estimation of reserves involves the exercise of judgement. Forecasts are
based on engineering data, future prices, expected future rates of production
and the timing of future capital expenditures, all of which are subject to
many uncertainties and interpretations. The Company expects that over time its
reserve estimates will be revised upward or downward based on updated
information such as the results of future drilling, testing and production
levels. Reserve estimates can have a significant impact on net earnings, as
they are a key component in the calculation of depletion, depreciation and
amortization and for determining potential asset impairment. For example, a
revision to the reserve estimate would result in a higher or lower DD&A charge
to net earnings. Downward revisions to reserve estimates could also result in
a write-down of crude oil and natural gas property, plant and equipment
carrying amounts under the ceiling test.
ASSET RETIREMENT OBLIGATION
Under CICA Handbook Section 3110, Asset Retirement Obligations ("ARO"), the
Company is required to recognize a liability for the future retirement
obligations associated with the Company's property, plant and equipment. An
ARO is recognized to the extent of a legal obligation associated with the
retirement of a tangible long-lived asset the Company is required to settle as
a result of an existing or enacted law, statute, ordinance or written or oral
contract, or by legal construction of a contract under the doctrine of
promissory estoppel. The ARO is based on estimated costs, taking into account
the anticipated method and extent of restoration consistent with legal
requirements, technological advances and the possible use of the site. Since
these estimates are specific to the sites involved, there are many individual
assumptions underlying the Company's total ARO amount. These individual
assumptions can be subject to change based on experience.
68 Management's Discussion & Analysis
The estimated fair values of asset retirement obligations related to long-term
assets are recognized as a liability in the period in which they are incurred.
Retirement costs equal to the estimated fair value of the asset retirement
obligations are capitalized as part of the cost of associated capital assets
and are amortized to expense through depletion over the life of the asset. The
fair value of the asset retirement obligation is estimated by discounting the
expected future cash flows to settle the asset retirement obligation at the
Company's average credit-adjusted risk-free interest rate of 6.8%. In
subsequent periods, the asset retirement obligation is adjusted for the
passage of time and for any changes in the amount or timing of the underlying
future cash flows. The estimates described impact earnings by way of depletion
on the capital cost and accretion on the asset retirement liability. In
addition, differences between actual and estimated costs to settle the asset
retirement obligation, timing of cash flows to settle the obligation and
future inflation rates could result in gains or losses on the final settlement
of the asset retirement obligations.
An ARO is not recognized for assets with an indeterminate useful life (e.g.
pipeline assets) because an amount cannot be reasonably estimated. An ARO for
these assets will be recorded in the first period in which the lives of these
assets are determinable.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various instruments to manage its commodity price and
foreign currency exposures on revenue, and interest rate exposures on US
dollar denominated debt. These derivative and financial instruments are not
used for trading or speculative purposes.
On January 1, 2004, the Company prospectively adopted the Canadian Institute
of Chartered Accountants' ("CICA") Accounting Guideline ("AcG") 13, "Hedging
Relationships" and Emerging Issues Committee ("EIC") 128, "Accounting for
Trading, Speculative or Non-Hedging Derivative Financial instruments".
Derivative instruments that do not qualify as hedges, or are not designated as
hedges, are recorded using the mark-to-market method of accounting whereby
instruments are recorded on the consolidated balance sheet as either an asset
or liability with changes in fair value recognized in net earnings. The
estimate of fair value of all derivative instruments is based on quoted market
prices or, in their absence, third party market indications. The cash
settlement amount of the risk management financial derivative instruments may
vary materially depending upon the underlying crude oil and natural gas prices
at the time of final settlement of the financial derivative instruments, as
compared to their mark-to-market value at December 31, 2005.
PURCHASE PRICE ALLOCATIONS
The costs of corporate and asset acquisitions are allocated to the acquired
assets and liabilities based on their estimated fair value at the time of
acquisition. The determination of fair value requires the Company to make
assumptions and estimates regarding future events. The allocation process is
inherently subjective and impacts the amount assigned to individually
identifiable assets and liabilities. As a result, the purchase price
allocation impacts the Company's reported assets and liabilities and future
net earnings due to the impact on future DD&A expense and impairment tests.
The Company has made various assumptions in determining the fair values of the
acquired assets and liabilities. The most significant assumptions and
judgments made relate to the estimation of the fair value of the crude oil and
natural gas properties. To determine the fair value of these properties, the
Company estimates (a) crude oil and natural gas reserves, and (b) future
prices of crude oil and natural gas. Reserve estimates are based on the work
performed by the Company's engineers and outside consultants. The judgments
associated with these estimated reserves are described above in "Crude oil and
natural gas reserves". Estimates of future prices are based on prices derived
from future price forecasts amongst industry analysts and internal
assessments. The Company applies estimated future prices to the estimated
reserves quantities acquired, and estimates future operating and development
costs, to arrive at estimated future net revenues for the properties acquired.
CONTROL ENVIRONMENT
Based on their evaluation as of December 31, 2005, the Company's President and
the Chief Financial Officer concluded, pursuant to Canadian Multilateral
Instrument 52-109 Part 2.1, that the Company's disclosure controls and
procedures are effective to ensure that information required to be disclosed
by the Company in its annual filings is recorded, processed, summarized and
reported within the time periods that meet the regulatory requirements. In
addition, as of December 31, 2005, there were no changes in the Company's
internal controls over financial reporting that occurred during 2005 that have
materially affected, or are reasonably likely to materially affect its
internal controls over financial reporting. The Company will continue to
periodically evaluate its disclosure controls and procedures and internal
controls over financial reporting and will make any modifications from time to
time as deemed necessary.
Management's Discussion & Analysis 69
NEW ACCOUNTING STANDARDS
In January 2005, the CICA issued four new standards relating to the
recognition, measurement and disclosure of financial instruments.
o Section 3855 - "Financial Instruments - Recognition and Measurement"
prescribes when a financial asset, financial liability, or
non-financial derivative is to be recognized on the balance sheet as
well as its measurement amount. This Section also specifies how
financial instruments gains and losses are to be presented.
Transitional provisions for this Section vary based on the type of
financial instruments under consideration.
o Section 3865 - "Hedges" expands on existing AcG 13 - "Hedging
Relationships", and Section 1650 "Foreign Currency Translation", by
specifying how hedge accounting is to be applied and what disclosures
are necessary when it is applied. Retroactive application of this
Section is not permitted.
o Section 1530 - "Comprehensive Income" introduces new standards for
reporting and disclosure of comprehensive income. Comprehensive
income is the change in equity (net assets) of the Company during a
reporting period from transactions and other events and circumstances
from non-owner sources. It includes all changes in equity during a
period except those resulting from investments by owners and
distributions to owners. Financial statements of prior periods are
required to be restated only for non-financial instrument items.
o Section 3251 - "Equity" replaces Section 3250 "Surplus" and
establishes standards for the presentation of equity and changes in
equity during a reporting period. Financial statements of prior
periods are required to be restated only for non-financial instrument
items. For all other items, comparative financial statements
presented are not restated, but an adjustment to the opening balance
of accumulated other comprehensive income may be required.
The Company plans to adopt these new standards effective January 1, 2007. The
effect on the Company's consolidated financial statements cannot be reasonably
determined at this time as the financial derivatives outstanding at December
31, 2006 and their related fair values are not known.
OUTLOOK
The Company continues to implement its strategy of maintaining a large
portfolio of varied projects, which the Company believes will enable it, over
an extended period of time, to provide consistent growth in production and
high shareholder returns. Annual budgets are developed, scrutinized throughout
the year and changed if necessary in the context of project returns, product
pricing expectations, and balance in project risk and time horizons. The
Company maintains a high ownership level and operatorship level in all of its
properties and can therefore control the nature, timing and extent of capital
expenditures in each of its project areas.
The Company expects production levels in 2006 to average 1,468 mmcf/d to 1,551
mmcf/d of natural gas and 335,000 bbl/d to 373,000 bbl/d of crude oil and
NGLs.
The budgeted capital expenditures in 2006 are currently expected to be as
follows: Drilling will comprise both deep and conventional targets, with new
production growth coming from the Company's Northeast British Columbia and
Northwest Alberta areas.
($ millions) 2006 Budget
------------------------------------------------------------------------------
North America natural gas $ 1,741
North America crude oil and NGLs 1,097
North Sea 733
Offshore West Africa 187
Property acquisitions, dispositions and midstream 63
------------------------------------------------------------------------------
3,821
Horizon Project Phase 1 Construction 2,561
Capitalized interest and other items 222
Horizon Project Phases 2/3 engineering 128
Canadian Natural Upgrader engineering 30
------------------------------------------------------------------------------
Total $ 6,762
==============================================================================
70 Management's Discussion & Analysis
NORTH AMERICA NATURAL GAS
The 2006 North American natural gas program will be as follows:
(number of wells) 2006 Budget
------------------------------------------------------------------------------
Northeast British Columbia 262
Northwest Alberta 147
Northern Plains 251
Southern Plains 479
------------------------------------------------------------------------------
Total 1,139
==============================================================================
NORTH AMERICA CRUDE OIL AND NGLS
The 2006 North America crude oil drilling program is highlighted by continued
development of Primrose North thermal production and another strong
conventional heavy program, as follows:
(number of wells) 2006 Budget
------------------------------------------------------------------------------
Conventional heavy crude oil 344
Thermal heavy crude oil 92
Light crude oil 111
Pelican Lake crude oil 150
------------------------------------------------------------------------------
Total 697
==============================================================================
The Company continues the disciplined development of its heavy crude oil
resources. Conventional heavy crude oil drilling is expected to increase,
reflecting favourable crude oil prices and new opportunities identified in the
property acquisitions made during 2004. Due to the nature of heavy crude oil
production patterns, where production volumes ramp up during the first months
of production, much of the production resulting from the expanded drill
program will not be realized until late 2007.
In 2006, the Company expects to continue its Primrose thermal crude oil
expansion plans. Activity in 2006 will be focused on the Primrose South
expansion. Production from this project is subject to the cycling of steam
injection and crude oil production and is expected to remain at similar levels
to the 2005 production. The waterflood conversion project is on schedule with
production response exceeding expectations. The Polymer Flood pilot project
has yielded positive results to date and will continue in 2006.
THE HORIZON PROJECT
The Horizon Project is designed as a phased development and includes two
components: the mining of bitumen and an onsite upgrader. Phase 1 production
is expected to commence in the second half of 2008 at 110,000 bbl/d of
34(degree) API light, sweet synthetic crude oil ("SCO"). The phased approach
provides the Company with improved cost and project controls including labour
and materials management, and directionally mitigates the effects of growth on
local infrastructure.
Construction costs for Phase 1 of the Horizon Project are estimated at $6.8
billion including a contingency reserve of $700 million, with $1.3 billion
incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion to be
incurred in 2007 and 2008.
Extensive front end design and the high degree of project definition have
enabled the Company to obtain approximately 68% of Phase 1 costs on a fixed
price basis. The high degree of up front project engineering and pre-planning
is expected to reduce the risks associated with scope changes.
NORTH SEA
The capital budget in 2006 for the North Sea is $733 million and includes the
drilling of approximately 12 net platform wells on Ninian, Murchison and
Tiffany. The Company will also conduct a mobile drilling program for which 6
subsea producer wells will be drilled at Columba E, Lyell, Toni and Thelma.
Average crude oil production is expected to increase from 2005 production
levels; however, natural gas volumes are expected to be flat as natural gas
production at the Banff Field is diverted to reinjection.
OFFSHORE WEST AFRICA
In 2006, the capital budget for Offshore West Africa is set at $187 million,
of which the Company anticipates $79 million to be spent on completing infill
drilling at East Espoir and developing the West Espoir Field. West Espoir
development is expected to yield first oil by mid-2006 at approximately 13,000
boe/d. Two additional wells will be completed at Baobab in 2006, allowing
production to ramp to approximately 35,000 bbl/d net to the Company. $32
million will be expended on development of the Olowi Field offshore Gabon in
2006, with first oil expected late in 2008.
Management's Discussion & Analysis 71
SENSITIVITY ANALYSIS (1)
The following table is indicative of the annualized sensitivities of cash flow
from operations and net earnings from changes in certain key variables. The
analysis is based on business conditions and sales volumes during the fourth
quarter of 2005. Each separate item in the sensitivity analysis shows the
effect of an increase in that variable only; all other variables are held
constant.
CASH FLOW FROM CASH FLOW FROM
OPERATIONS OPERATIONS NET EARNINGS NET EARNINGS
($ millions) ($/share, basic) ($ millions) ($/share, basic)
-------------------------------------------------------------------------------------------------------------
Price changes
Crude oil - WTI US$1.00/bbl (2)
Excluding financial derivatives $ 113 $ 0.21 $ 79 $ 0.15
Including financial derivatives $ 60 $ 0.11 $ 40 $ 0.07
Natural gas - AECO C$0.10/mcf (2)
Excluding financial derivatives $ 38 $ 0.07 $ 24 $ 0.05
Including financial derivatives $ 14 $ 0.03 $ 8 $ 0.01
Volume changes
Crude oil - 10,000 bbl/d $ 104 $ 0.19 $ 53 $ 0.10
Natural gas - 10 mmcf/d $ 32 $ 0.06 $ 17 $ 0.03
Foreign currency rate change
$0.01 change in C$ in relation to US$ (2) $ 82-84 $ 0.15-0.16 $ 32-33 $ 0.06
Interest rate change - 1% $ 7 $ 0.01 $ 7 $ 0.01
=============================================================================================================
(1) The sensitivities are calculated based on 2005 fourth quarter results
excluding mark-to-market gains (losses) on risk management activities.
(2) For details of financial instruments in place, refer to note 10 to the
Company's audited annual consolidated financial statements as at December
31, 2005.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES (1)
Q1 Q2 Q3 Q4 2005 2004 2003
--------------------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 209,125 215,693 231,260 230,263 221,669 206,225 174,895
North Sea 71,139 62,884 73,543 66,798 68,593 64,706 56,869
Offshore West Africa 7,539 10,487 29,921 43,207 22,906 11,558 10,628
--------------------------------------------------------------------------------------------------------
Total 287,803 289,064 334,724 340,268 313,168 282,489 242,392
--------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,430 1,434 1,400 1,402 1,416 1,330 1,245
North Sea 23 17 18 15 19 50 46
Offshore West Africa 2 3 5 6 4 8 8
--------------------------------------------------------------------------------------------------------
Total 1,455 1,454 1,423 1,423 1,439 1,388 1,299
--------------------------------------------------------------------------------------------------------
Barrels of oil equivalent (boe/d)
North America 447,446 454,602 464,607 463,869 457,695 427,936 382,315
North Sea 74,956 65,751 76,545 69,361 71,651 73,093 64,469
Offshore West Africa 7,914 11,027 30,759 44,275 23,614 12,806 12,030
--------------------------------------------------------------------------------------------------------
Total 530,316 531,380 571,911 577,505 552,960 513,835 458,814
--------------------------------------------------------------------------------------------------------
(1) The Company recognizes revenue on its crude oil production when title
transfers to the customer and delivery has taken place. For production
where revenue has not yet been recognized, the related crude oil
inventory volumes, by segment, were as follows at December 31, 2005:
(bbls) 2005
--------------------------------------------------------------------------------------------------------
North America, related to Corsicana pipeline line fill 484,157
North Sea, related to timing of liftings 747,141
Offshore West Africa, related to timing of liftings, net of government entitlement to
profit oil 412,841
--------------------------------------------------------------------------------------------------------
1,644,139
========================================================================================================
At December 31, 2004, variances between production volumes and liftings were
not significant.
72 Management's Discussion & Analysis
PER UNIT RESULTS (1)
Q1 Q2 Q3 Q4 2005 2004 2003
-------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
Sales price (2) $ 39.81 $ 42.51 $ 57.35 $ 46.38 $ 46.86 $ 37.99 $ 32.66
Royalties 3.39 3.33 5.11 3.89 3.97 3.16 2.77
Production expense 11.30 11.66 11.48 10.33 11.17 10.05 10.28
-------------------------------------------------------------------------------------------------------------
Netback $ 25.12 $ 27.52 $ 40.76 $ 32.16 $ 31.72 $ 24.78 $ 19.61
-------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (2) $ 6.68 $ 7.33 $ 8.61 $ 11.67 $ 8.57 $ 6.50 $ 6.21
Royalties 1.30 1.48 1.93 2.30 1.75 1.35 1.32
Production expense 0.69 0.71 0.76 0.76 0.73 0.67 0.60
-------------------------------------------------------------------------------------------------------------
Netback $ 4.69 $ 5.14 $ 5.92 $ 8.61 $ 6.09 $ 4.48 $ 4.29
-------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Sales price (2) $ 39.94 $ 43.05 $ 54.87 $ 56.08 $ 48.77 $ 38.45 $ 34.84
Royalties 5.42 5.85 7.84 8.01 6.82 5.37 5.20
Production expense 8.04 8.29 8.56 7.93 8.21 7.35 7.15
-------------------------------------------------------------------------------------------------------------
Netback $ 26.48 $ 28.91 $ 38.47 $ 40.14 $ 33.74 $ 25.73 $ 22.49
=============================================================================================================
(1) Amounts expressed on a per unit basis are based on sales volume.
(2) Including transportation costs and excluding risk management activities.
NETBACK ANALYSIS
($/boe) (1) 2005 2004 2003
------------------------------------------------------------------------------------------------------------
Sales price (2) $ 48.77 $ 38.45 $ 34.84
Royalties 6.82 5.37 5.20
Production expense (3) 8.21 7.35 7.15
------------------------------------------------------------------------------------------------------------
Netback 33.74 25.73 22.49
Midstream contribution (3) (0.26) (0.26) (0.28)
Administration (4) 0.75 0.66 0.52
Interest, net 0.74 1.01 1.20
Realized risk management activities loss 5.13 2.52 1.09
Realized foreign exchange (gain) loss (0.15) 0.02 0.05
Taxes other than income tax - current 1.01 1.12 0.69
Current income tax - North America 0.41 0.47 0.14
Current income tax - Large Corporations Tax 0.08 0.05 0.06
Current income tax - North Sea 0.77 0.01 0.26
Current income tax - Offshore West Africa 0.17 0.07 0.09
Current income tax - other 0.01 0.01 --
------------------------------------------------------------------------------------------------------------
Cash flow $ 25.08 $ 20.05 $ 18.67
============================================================================================================
(1) Amounts expressed on a per unit basis are based on sales volume.
(2) Including transportation costs and excluding risk management activities.
(3) Excluding inter-segment eliminations.
(4) Restated to conform to current year presentation.
TRADING AND SHARE STATISTICS
Q1 Q2 Q3 Q4 2005 Total 2004 Total(1)
--------------------------------------------------------------------------------------------------------------------------
TSX - C$
Trading volume (thousands) 169,018 155,274 160,121 153,579 637,992 606,024
Share price ($/share)
High $ 37.38 $ 46.98 $ 60.00 $ 62.00 $ 62.00 $ 27.58
Low $ 24.28 $ 30.54 $ 45.52 $ 43.55 $ 24.28 $ 15.96
Close $ 34.18 $ 44.40 $ 52.50 $ 57.63 $ 57.63 $ 25.63
Market capitalization at December 31 ($ millions) $ 30,910 $ 13,744
Shares outstanding (thousands) 536,348 536,361
--------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading volume (thousands) 48,333 68,743 66,802 67,676 251,554 125,468
Share price ($/share)
High $ 30.37 $ 38.03 $ 50.73 $ 54.05 $ 54.05 $ 22.37
Low $ 19.74 $ 24.49 $ 36.87 $ 36.65 $ 19.74 $ 11.94
Close $ 28.41 $ 36.38 $ 45.19 $ 49.62 $ 49.62 $ 21.39
Market capitalization at December 31 ($ millions) $ 26,614 $ 11,470
Shares outstanding (thousands) 536,348 536,361
==========================================================================================================================
(1) Restated to reflect two-for-one share split in May 2005.
Management's Discussion & Analysis 73
TEN-YEAR REVIEW
Years ended December 31 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996
---------------------------------------------------------------------------------------------------------------------------------
FINANCIAL INFORMATION
(C$ millions, except per share amounts)
Net earnings 1,050 1,405 1,403 539 639 758 213 31 104 88
Per share - basic (1) $ 1.96 $ 2.62 $ 2.62 $ 1.06 $ 1.32 $ 1.62 $ 0.51 $ 0.08 $ 0.26 $ 0.27
Cash flow from operations (2) 5,021 3,769 3,160 2,254 1,290 1,884 724 444 503 360
Per share - basic (1) $ 9.36 $ 7.03 $ 5.88 $ 4.41 $ 3.96 $ 4.04 $ 1.74 $ 1.12 $ 1.28 $ 1.08
---------------------------------------------------------------------------------------------------------------------------------
Capital expenditures, net of dispositions
(including business combinations) 4,932 4,633 2,506 4,069 1,885 2,823 1,901 610 1,119 1,204
---------------------------------------------------------------------------------------------------------------------------------
Balance Sheet information
Working capital (deficiency) surplus (1,774) (652) (505) (14) (6) (77) 36 58 (19) (1)
Property, plant and equipment, net 19,694 17,064 13,714 12,934 8,766 7,439 4,679 3,135 2,831 1,993
Total assets 21,852 18,372 14,643 13,793 9,290 8,051 4,976 3,329 3,016 2,144
Long-term debt 3,321 3,538 2,748 4,200 2,788 2,573 2,157 1,426 1,136 588
Shareholders' equity 8,237 7,324 6,006 4,754 3,928 3,297 1,962 1,317 1,250 1,108
---------------------------------------------------------------------------------------------------------------------------------
SHARE INFORMATION
Common shares outstanding (thousands) 536,348 536,361 534,926 535,104 484,804 489,116 445,816 399,236 395,276 389,532
Weighted average shares
outstanding (thousands) 536,650 536,223 536,940 511,532 485,200 466,804 415,624 397,324 392,168 332,984
Dividends declared per common share $ 0.24 $ 0.20 $ 0.15 $ 0.13 $ 0.10 $ - $ - $ - $ - $ -
---------------------------------------------------------------------------------------------------------------------------------
Trading statistics (1)
TSX-C$
Trading volume (thousands) 637,992 606,024 590,702 619,316 534,976 567,412 430,460 410,440 402,152 396,888
Share Price ($/share)
High $ 62.00 $ 27.58 $ 16.81 $ 13.64 $ 13.09 $ 14.05 $ 9.65 $ 7.88 $ 11.06 $ 9.85
Low $ 24.28 $ 15.96 $ 11.30 $ 9.40 $ 8.98 $ 7.45 $ 4.95 $ 4.56 $ 7.23 $ 4.81
Close $ 57.63 $ 25.63 $ 16.34 $ 11.70 $ 9.58 $ 10.38 $ 8.81 $ 5.75 $ 7.65 $ 9.40
---------------------------------------------------------------------------------------------------------------------------------
NYSE-US$
Trading volume (thousands) 251,554 l25,468 46,916 31,864 20,764 3,172 - - - -
Share Price ($/share)
High $ 54.05 $ 22.37 $ 12.85 $ 8.72 $ 8.63 $ 9.46 $ - $ - $ - $ -
Low $ 19.74 $ 11.94 $ 7.32 $ 5.89 $ 5.70 $ 6.19 $ - $ - $ - $ -
Close $ 49.62 $ 21.39 $ 12.61 $ 7.42 $ 6.10 $ 6.88 $ - $ - $ - $ -
---------------------------------------------------------------------------------------------------------------------------------
RATIOS
Debt to cash flow (3) 0.7x 1.0x 0.9x 1.9x 1.5x 1.4x 3.0x 3.2x 2.3x 1.6x
Debt to book capitalization (3) 28.7% 33.8% 32.8% 47.1% 41.7% 44.0% 52.4% 52.0% 47.6% 34.7%
Return on average common shareholders'
equity, after tax (3) 14.3% 21.4% 25.6% 13.0% 17.7% 28.8% 13.0% 2.4% 8.8% 10.9%
Debt to EBITDA (3) 0.6x 0.9x 0.8x 1.7x 1.4x 1.2x 2.6x 2.9x 4.8x 3.Ox
Daily production before royalties per
ten thousand common shares (boe/d) 10.3 9.6 8.5 8.2 7.4 6.6 5.0 4.7 4.5 3.6
Conventional proved and probable
reserves per common share (boe) (4) 4.8 4.3 4.0 3.3 3.1 2.9 2.4 1.9 1.7 1.3
Net asset value
per common share (1)(5) 60.44 33.13 23.35 19.57 16.88 20.54 12.33 8.08 6.80 6.46
=================================================================================================================================
(1) Restated to reflect two-for-one share splits in May 2004 and May 2005.
(2) Cash flow from operations is a non-GAAP term that represents net earnings
adjusted for non-cash items. The Company evaluates its performance based
on earnings and cash flow. Cash flow from operations may not be
comparable to similar measures used by other companies.
(3) Refer to the MD&A, page 62, "Liquidity and Capital Resources", for the
definitions of these items.
(4) Based upon constant dollar Company gross reserves (before royalties),
using year-end common shares outstanding.
(5) Based upon 10% discounted, forecast price pre-tax proved and probable net
present values as reported in the Company's AIF for conventional
reserves, with $250/acre added for core undeveloped land in 2005 and
$75/acre for all years prior, less long-term debt and existing asset
liabilities and adjusted for working capital. See reserves disclosures on
pages 40 to 44.
74 Ten-Year Review
Years ended December 31 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996
-------------------------------------------------------------------------------------------------------------------------
OPERATING INFORMATION
Conventional crude oil and NGLs (mmbbl)
-------------------------------------------------------------------------------------------------------------------------
Company gross proved reserves
(before royalties)
North America 785 695 672 665 644 643 554 284 257 136
North Sea 290 303 222 203 83 102 - - - -
Offshore West Africa 148 125 106 94 61 36 - - - -
-------------------------------------------------------------------------------------------------------------------------
1,223 1,123 1,000 962 788 781 554 284 257 136
-------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable reserves
(before royalties)
North America 1,154 992 977 742 740 731 640 380 329 185
North Sea 417 415 317 277 106 134 - - - -
Offshore West Africa 230 214 187 162 1ll 46 - - - -
-------------------------------------------------------------------------------------------------------------------------
1,801 1,621 1,481 1,181 957 911 640 380 329 185
-------------------------------------------------------------------------------------------------------------------------
Conventional natural gas (bcf)
Company gross proved
reserves (before royalties)
North America 3,378 3,202 3,006 3,048 2,566 2,360 2,183 1,901 1,716 1,566
North Sea 29 27 62 71 94 91 - - - -
Offshore West Africa 83 81 86 90 69 65 - - - -
-------------------------------------------------------------------------------------------------------------------------
3,490 3,310 3,154 3,209 2,729 2,516 2,183 1,901 1,716 1,566
-------------------------------------------------------------------------------------------------------------------------
Company gross proved and
probable reserves (before
royalties)
North America 4,372 4,100 3,611 3,450 2,915 2,762 2,547 2,211 2,078 1,926
North Sea 69 57 101 89 118 114 - - - -
Offshore West Africa 127 102 111 120 96 84 - - - -
-------------------------------------------------------------------------------------------------------------------------
4,568 4,259 3,823 3,659 3,129 2,960 2,547 2,211 2,078 1,926
-------------------------------------------------------------------------------------------------------------------------
Total proved reserves
(before royalties) (mmboe) 1,804 1,674 1,526 1,497 1,243 1,200 918 601 543 397
-------------------------------------------------------------------------------------------------------------------------
Total proved and probable reserves
(before royalties) (mmboe) 2,562 2,330 2,118 1,791 1,479 1,404 1,065 749 675 506
-------------------------------------------------------------------------------------------------------------------------
Oil sands, mining (mmbbl)
Gross proved and probable
reserves (before royalties)
Bitumen 3,430 - - - - - - - - -
Synthetic crude oil * 2,878 - - - - - - - - -
-------------------------------------------------------------------------------------------------------------------------
Daily production (before royalties)
Crude oil and NGLs (mbbl/d)
North America 222 206 175 169 167 155 87 76 71 37
North Sea 68 65 57 39 36 17 - - - -
Offshore West Africa 23 12 10 7 3 2 - - - -
-------------------------------------------------------------------------------------------------------------------------
313 283 242 215 206 174 87 76 71 37
-------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,416 1,330 1,245 1,204 906 793 721 673 626 499
North Sea 19 50 46 27 12 1 - - - -
Offshore West Africa 4 8 8 1 - - - - - -
-------------------------------------------------------------------------------------------------------------------------
1,439 1,388 1,299 1,232 918 794 721 673 626 499
-------------------------------------------------------------------------------------------------------------------------
Total production
(before royalties)(mboe/d) 553 514 459 421 359 306 207 188 175 120
-------------------------------------------------------------------------------------------------------------------------
Product pricing
Average crude oil and NGLs
price ($/bbl) 46.86 37.99 32.66 31.22 23.45 31.89 22.26 11.98 18.99 24.73
Average natural gas price ($/mcf) 8.57 6.50 6.21 3.77 5.45 4.92 2.52 2.11 1.97 1.67
=========================================================================================================================
* SCO reserves are based upon upgrading of the bitumen reserves. The reserves
shown for bitumen and SCO are not additive.
Ten-Year Review 75
ADDITIONAL DISCLOSURE
DISCLOSURE CONTROLS AND PROCEDURES
----------------------------------
As of the end of the registrant's fiscal year ended December 31, 2005, an
evaluation of the effectiveness of Canadian Natural's "disclosure controls and
procedures" (as such term is defined in Rules 13a-15(c) and 15d-15(e) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act") was carried
out by Canadian Natural's principal executive officer and principal financial
officer. Based upon the evaluation, Canadian Natural's principle executive
officer and principal financial officer have concluded that as of the end of
the fiscal year, Canadian Natural's disclosure controls and procedures are
effective to ensure that information required to be disclosed by the
registrant in reports that it files or submits under the Exchange Act is (i)
recorded, processed, summarized and reported within the time periods specified
in Securities and Exchange Commission rules and forms and (ii) accumulated and
communicated to the registrant's management, including its principal executive
officer and principal financial officer, to allow timely decisions regarding
required disclosure.
It should be noted that while Canadian Natural's principal executive officer
and principal financial officer believe that Canadian Natural's disclosure
controls and procedures provide a reasonable level of assurance that they are
effective, they do not expect the Canadian Natural's disclosure controls and
procedures or internal control over financial reporting will prevent all
errors and fraud. A control system, no matter how well conceived or operated,
can provide only reasonable, not absolute, assurance that the objectives of
the control system are met.
During the fiscal year ended December 31, 2005, there were no changes in the
registrant's internal controls over financial reporting that have materially
affected, or are reasonably likely to materially affect, the registrant's
internal controls over financial reporting.
NOTICES PURSUANT TO REGULATION BTR
----------------------------------
None
AUDIT COMMITTEE FINANCIAL EXPERT
--------------------------------
The Board of Directors of Canadian Natural has determined that Ms. C.M. Best
qualifies as an "audit committee financial expert" (as defined in paragraph
8(b) of General Instruction B to the Form 40-F) serving on its Audit
Committee. Ms. C.M. Best is, as are all members of the Audit Committee of the
Board of Directors of Canadian Natural, "independent" as such term is defined
in the New York Stock Exchange Listed Company Manual.
CODE OF ETHICS
--------------
Canadian Natural has a long-standing Code of Integrity, Business Ethics and
Conduct (the "Code of Ethics"), which covers such topics as employment
standards, conflict of interest, the treatment of confidential information and
trading in Canadian Natural's shares, to ensure that Canadian Natural's
business is conducted in a consistently legal and ethical manner. Each
director and all employees, including each member of senior management and
more specifically the principal executive officers, the principal financial
officer and the principal accounting officer, are required to abide by the
Code of Ethics. The Nominating and Corporate Governance Committee periodically
reviews the Code of Ethics to ensure it addresses appropriate topics and
complies with regulatory requirements and recommends any appropriate changes
to the Board for approval.
Any waivers of or amendments to the Code of Ethics must be approved by the
Board of Directors and will be appropriately disclosed. No waivers and no
implicit waivers to the Code of Ethics in whole or in part have been asked for
or granted to any director, senior officer or employee as of the date of this
Annual Report.
The Code of Ethics is available through the System for Electronic Document and
Analysis and Retrieval (SEDAR) at WWW.SEDAR.COM. Requests for copies can also
be made by contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural
Resources Limited, 2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P
4J8.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
--------------------------------------
PricewaterhouseCoopers LLP ("PwC") has been the auditor of Canadian Natural
since Canadian Natural's inception. The aggregate amounts billed by PwC for
each of the last two fiscal years for audit fees, audit-related fees, tax fees
and all other fees, excluding expenses, are set forth below.
AUDIT FEES: The aggregate fees billed for each of the last two fiscal
years of Canadian Natural ending December 31, 2005 and December 31, 2004, for
professional services rendered by PwC for the audit of its annual consolidated
financial statements in connection with statutory and regulatory filings or
engagements for those fiscal years, unaudited reviews of the first, second and
third quarters of its interim consolidated financial Statements and audits of
certain of Canadian Natural's subsidiary companies' annual financial
statements were $1,200,235 and $1,100,548, respectively.
AUDIT-RELATED FEES: The aggregate fees billed for each of the last two
fiscal years of Canadian Natural, ending December 31, 2005 and December 31,
2004, for audit-related services by PwC consisting of debt covenant
compliance, Crown Royalty Statements, and services related to internal control
reviews and assistance with Sarbanes-Oxley Section 404 relating to internal
control reporting requirements were, $266,923 and $183,663 respectively.
Canadian Natural's Audit Committee approved all of these audit-related
services.
TAX FEES: The aggregate fees billed for each of the last two fiscal
years of Canadian Natural, ending December 31, 2005 and December 31, 2004, for
professional services rendered by PwC for tax-related services related to
expatriate personal tax and compliance as well as other corporate tax return
matters provided in 2005 were $39,331 and $39,330, respectively. Canadian
Natural's Audit Committee approved all of these tax-related services.
ALL OTHER FEES: The aggregate fees billed for each of the last two
fiscal years of Canadian Natural, ending December 31, 2005 and December 31,
2004 for other services were $7,290 and $nil respectively. The fees for other
services paid in 2005 related to accessing resource materials through PwC's
accounting literature library. Canadian Natural's Audit Committee approved all
of the noted services.
AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES:
The Audit Committee's duties and responsibilities include the review and
approval of fees to be paid to the independent auditors, scope and timing of
the audit and other related services rendered by the independent auditors. The
Audit Committee also reviews and approves the independent auditor's annual
audit plan, including scope, staffing, locations and reliance upon management
and internal audit department prior to the commencement of the audit and
reviews and approves proposed non-audit services to be provided by the
independent auditors, except those non-audit services prohibited by
legislation. Canadian Natural did not rely on the de minimis exemption
provided by paragraph (c)(7)(i)(c) of Rule 2.01 of Regulation S-X in 2005.
OFF-BALANCE SHEET ARRANGEMENTS
------------------------------
Canadian Natural does not have any off-balance sheet arrangements that have or
are reasonably likely to have an effect on its results of operations or
financial condition. See page 65 of Canadian Natural's Management's Discussion
and Analysis of Financial Condition and Results of Operations for the fiscal
year ended December 31, 2005, filed herewith, under the caption "Commitments
and Off Balance Sheet Arrangements".
CONTRACTUAL OBLIGATIONS
-----------------------
In the normal course of business, the Company has entered into various
contractual arrangements and commitments that will have an impact on the
Company's future operations. These contractual obligations and commitments
primarily relate to debt repayments, operating leases relating to office space
and offshore production and storage vessels, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to asset retirement obligations. The Company has not entered into any
contracts that would require consolidation under CICA Accounting Handbook,
AcG-15, Consolidation of Variable Interest Entities. The following table
summarizes the Company's commitments as at December 31, 2005:
-------------------------------------------------------------------------------------------------------------------------
($ MILLIONS) TOTAL 2006 2007 2008 2009 2010 THEREAFTER
-------------------------------------------------------------------------------------------------------------------------
Product transportation and pipline 1,766 195 133 148 94 85 1,111
-------------------------------------------------------------------------------------------------------------------------
Offshore equipment and leasing 436 51 51 52 51 51 180
-------------------------------------------------------------------------------------------------------------------------
Offshore drilling 267 132 100 35 - - -
-------------------------------------------------------------------------------------------------------------------------
Asset Retirement Obligation(1) 3,325 82 4 4 4 7 3,224
-------------------------------------------------------------------------------------------------------------------------
Long-term debt(2) 3,199 - 161 36 36 - 2,966
-------------------------------------------------------------------------------------------------------------------------
Other(3) 204 61 62 21 29 23 8
-------------------------------------------------------------------------------------------------------------------------
TOTAL 9,197 521 511 296 214 166 7,489
=========================================================================================================================
(1) Represents management's estimate of the future payments to settle asset
retirement obligations related to resource properties, facilities,
production platforms and pipelines, based on current legislation and
industry operating practices.
(2) No debt repayments are reflected for the bank credit facilities due to
the extendable nature of the facilities. As at December 31, 2005 there
was $122 million outstanding owed under the bank credit facilities.
(3) Consists of future expenditures related primarily to office lease,
electricity and crude oil processing.
Total construction costs for the three phases of the Horizon Project
development are expected to be approximately $10.8 billion. The Board of
Directors has approved the construction costs for Phase 1 of the Horizon
Project, which are expected to be $6.8 billion, including a contingency fund
of $700 million, with $1.3 billion incurred in 2005, $2.6 billion forecast to
be incurred in 2006 and $2.9 billion forecast to be incurred in 2007 and 2008
combined.
The Company is defendant and plaintiff in a number of legal actions that arise
in the normal course of business. The Company believes that any liabilities
that might arise pertaining to such matters would not have a material effect
on its consolidated financial position.
IDENTIFICATION OF THE AUDIT COMMITTEE
-------------------------------------
Canadian Natural has a separately designated standing audit committee
established in accordance with section 3(a)(58)(A) of the Exchange Act. The
members of the Audit Committee are Messrs. G. A. Filmon, G. D. Giffin, D. A.
Tuer and Ms. C.M. Best who chairs the Audit Committee.
NEW YORK STOCK EXCHANGE DISCLOSURE
----------------------------------
PRESIDING DIRECTOR AT MEETINGS OF NON-MANAGEMENT DIRECTORS
----------------------------------------------------------
Canadian Natural schedules executive sessions at each regularly scheduled
Board of Directors meeting in which Canadian Natural's "non-management
directors" (as that term is defined in the rules of the New York Stock
Exchange) meet without management participation. Mr. G. D. Giffin serves as
the presiding director (the "Presiding Director") at such sessions and in his
absence the non-management directors appoint a Presiding Director from among
the non-management directors.
COMMUNICATION WITH NON-MANAGEMENT DIRECTORS
-------------------------------------------
Shareholders may send communications to Canadian Natural's non-management
directors by writing to the Presiding Director, c/o Bruce E. McGrath,
Corporate Secretary, Canadian Natural Resources Limited, 2500, 855 - 2nd
Street S.W., Calgary, Alberta, T2P 4J8. Communications will be referred to the
Presiding Director for appropriate action. The status of all outstanding
concerns addressed to the Presiding Director will be reported to the board of
directors as appropriate.
CORPORATE GOVERNANCE GUIDELINES
-------------------------------
In accordance with Section 303A.09 of the NYSE Listed Company Manual, Canadian
Natural has adopted a set of corporate governance guidelines, which are
available in print at no charge to any shareholder who requests them. Requests
for copies of the corporate governance guidelines should be made by
contacting: Bruce E. McGrath, Corporate Secretary, Canadian Natural Resources
Limited, 2500-855 2nd Street, S.W., Calgary, Alberta, Canada T2P 4J8. The
corporate governance guidelines are attached as a schedule to the Information
Circular for the Annual General Meeting of Shareholders which is available
through the System for Electronic Document and Analysis and Retrieval (SEDAR)
at WWW.SEDAR.COM
BOARD COMMITTEE CHARTERS
------------------------
The charters of Canadian Natural's Audit Committee, Nominating and Corporate
Governance Committee and Compensation Committee are available in print at no
charge to any shareholder who requests them. Requests for copies of these
documents should be made by contacting: Bruce E. McGrath, Corporate Secretary,
Canadian Natural Resources Limited, 2500-855 2nd Street, S.W., Calgary,
Alberta, Canada T2P 4J8. The Charter of Canadian Natural's Audit Committee is
also attached as a schedule to Canadian Natural's Annual Information Form for
year ending December 31, 2005, which forms part of this Form 40-F. The Annual
Information Form is also available through the System for Electronic Document
and Analysis and Retrieval (SEDAR) at www.sedar.com.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
UNDERTAKING
Canadian Natural undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities
in relation to which the obligation to file an annual report on Form 40-F
arises; or transactions in said securities.
CONSENT TO SERVICE OF PROCESS
The Company has previously filed a Form F-X in connection with the class of
securities in relation to which the obligation to file this report arises.
Any change to the name or address of the agent for service of process of
Canadian Natural shall be communicated promptly to the Commission by an
amendment to the Form F-X referencing the file number of the relevant
registration statement.
SIGNATURES
Pursuant to the requirements of the Exchange Act, Canadian Natural certifies
that it meets all of the requirements for filing on Form 40-F and has duly
caused this Annual Report to be signed on its behalf by the undersigned,
thereto duly authorized.
Dated this 29th day of March, 2006.
CANADIAN NATURAL RESOURCES LIMITED
By: /s/ Steve W. Laut
-----------------------------
Name: Steve W. Laut
Title: President and Chief
Operating Officer
Documents filed as part of this report:
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------- -----------
1. Supplementary Oil & Gas Information for the fiscal year ended
December 31, 2005.
2. Certification of Chief Executive Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
3. Certification of Chief Financial Officer pursuant to Rule
13a-14(a) or 15d-14 of the Securities Exchange Act of 1934.
4. Certification of Chief Executive Officer pursuant to Rule
13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the
United States Code (18 U.S.C. 1350).
5. Certification of Chief Financial Officer pursuant to Rule
13(a)-14(b) and Section 1350 of Chapter 63 of Title 18 of the
United States Code (18 U.S.C. 1350).
6. Consent of PricewaterhouseCoopers LLP, independent chartered
accountants.
7. Consent of Sproule Associates Limited, independent petroleum
engineering consultants.
8. Consent of Ryder Scott Company, independent petroleum
engineering consultants.
9. Consent of Gilbert Laustsen Jung Associates Ltd., independent
petroleum engineering consultants.