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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, 2006 Commission File Number: 333-12138
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:
TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED:
Common Shares, no par value New York 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.
537,903,260 Common Shares outstanding as of December 31, 2006
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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. 333-138873) under the Securities Act of 1933.
PRINCIPAL DOCUMENTS
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, 2006.
B. AUDITED ANNUAL FINANCIAL STATEMENTS
Canadian Natural's audited consolidated financial statements for the
years ended December 31, 2006 and 2005, including the auditors' report
with respect thereto. For a reconciliation of important differences
between Canadian and United States generally accepted accounting
principles, see Note 16 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, 2006.
SUPPLEMENTARY OIL & GAS INFORMATION
For Canadian Natural's Supplementary Oil & Gas Information for the year ended
December 31, 2006, see Exhibit 1 of this Annual Report on Form 40-F.
1
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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 28, 2007
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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...........................................................12
RISK FACTORS.................................................................13
ENVIRONMENTAL MATTERS........................................................19
DESCRIPTION OF THE BUSINESS..................................................20
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES...............21
DRILLING ACTIVITY...................................................22
PRODUCING CRUDE OIL AND NATURAL GAS WELLS...........................23
NORTHEAST BRITISH COLUMBIA..........................................23
NORTHWEST ALBERTA...................................................24
NORTHERN PLAINS.....................................................25
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN..........................28
HORIZON OIL SANDS PROJECT...........................................30
UNITED KINGDOM NORTH SEA............................................32
OFFSHORE WEST AFRICA................................................33
COTE D'IVOIRE.......................................................33
ANGOLA..............................................................34
GABON...............................................................35
B. CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES....................36
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES..................41
D. OIL SANDS MINING DISCLOSURE.............................................42
E. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION..............................49
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT.................................54
G. NET CAPITAL EXPENDITURES................................................55
H. UNDEVELOPED ACREAGE.....................................................58
I. DEVELOPED ACREAGE.......................................................58
SELECTED FINANCIAL INFORMATION...............................................59
2
CAPITAL STRUCTURE............................................................60
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES.....................61
DIVIDEND HISTORY.............................................................62
TRANSFER AGENTS AND REGISTRAR................................................63
DIRECTORS AND OFFICERS.......................................................63
CONFLICTS OF INTEREST........................................................68
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................68
AUDIT COMMITTEE INFORMATION..................................................69
LEGAL PROCEEDINGS............................................................70
MATERIAL CONTRACTS...........................................................70
INTERESTS OF EXPERTS.........................................................70
ADDITIONAL INFORMATION.......................................................71
SCHEDULE "A" REPORT ON RESERVES DATA.........................................72
SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS..............................75
SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE..................................77
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:
"ARO" means Asset Retirement Obligation
"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.
"CBM" means coalbed methane
"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 Offtake vessel.
"GHG" means greenhouse gas.
"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.
"HORIZON PROJECT" means the Horizon Oil Sands Project
"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.
4
"NGLS" means natural gas liquids.
"NET ACRES" refers to gross acres multiplied by the percentage working interest
therein owned or to be owned by the Company.
"NET WELLS" refers to gross wells multiplied by the percentage working interest
therein owned or to be owned by the Company.
"PRODUCTIVE WELL" means a well that is not a dry well.
"PRT" means Petroleum Revenue Tax
"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 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 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 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
crude oil and natural gas in common units called barrel of oil equivalent
("boe"). A boe is derived by converting six thousand cubic feet of natural gas
to one barrel of crude oil (6mcf:1bbl). This conversion may be misleading,
6
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, 2006, 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, as well as proved and probable crude oil, natural gas
liquids ("NGL") and natural gas reserves (not including the Company's oil sands
mining assets) and prepare Evaluation Reports on these reserves. Sproule
evaluated the Company's North America conventional assets and Ryder Scott
evaluated the 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
Security and Exchange Commission ("SEC") requirements for certain disclosures
required under NI 51-101. There are two principal differences between the two
standards (i) the 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; and, (ii) the definition
of proved reserves used by the SEC to that of NI 51-101. However with respect
to the definition of proved reserves, 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
should not be material.
For the year ended December 31, 2006, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants Ltd. ("GLJ"), to
evaluate 100% of Phases 1 through 3 of the Company's Horizon Oil Sands Project
("Horizon 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 proved and probable
crude oil, NGLs and natural gas reserves.
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 crude oil and natural gas
information section of the Company's Annual Report. The Company has elected to
provide the net present value of these same conventional proved reserves as
well as its conventional proved and probable reserves and the net present value
of these reserves under the same parameters as additional voluntary
information. 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.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 this Annual Information
Form.
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, NGLs and natural gas
reserves as well as the Company's quantity of oil sands mining reserves.
7
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
Management's Discussion and Analysis ("MD&A") 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 net asset
value. 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.
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.
On September 14, 2006, the Company announced entering into an agreement to
acquire Anadarko Canada Corporation, a subsidiary of Anadarko Petroleum
Corporation for net cash consideration of $4,641 million including working
capital and other adjustments. Pursuant to a Purchase and Sale Agreement, the
Company acquired all of the outstanding shares of Anadarko Canada Corporation
effective November 2, 2006. On November 3, 2006 Anadarko Canada Corporation and
a wholly owned subsidiary of the Company, 1266701 Alberta Ltd. amalgamated to
form ACC-CNR Resources Corporation. Subsequently, on January 1, 2007, ACC-CNR
Resources Corporation and Canadian Natural Resources Limited amalgamated and
the amalgamated company continued under the name Canadian Natural Resources
Limited.
8
The main operating subsidiaries of the Company, each of which is directly or
indirectly wholly-owned, and their jurisdictions of incorporation are as
follows:
NAME OF COMPANY JURISDICTION OF INCORPORATION
--------------- -----------------------------
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 (Olowi) 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, as the managing partner, CNR (ECHO) Resources
Inc., Renata Resources Inc., and Canadian Natural Resources 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. 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 situated in Alberta. Canadian Natural, as the managing partner, and CNR
2006 ULC are the partners of CNR 2006 Partnership, which holds certain crude
oil and natural gas properties situated in the provinces of Alberta,
Saskatchewan and British Columbia and in the Yukon Territories.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.
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 NGLs, natural gas and bitumen production.
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 net 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, 2006 the Company had 3,360
permanent employees in North America and 340 permanent employees in its
international operations.
9
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. 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
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.
10
In February 2005, the Board of Directors of the Company approved Phase 1 of the
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"). Future expansion using
a phased approach would further increase production to 232 mbbl/d of 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.
Based upon stratigraphic drilling and the Company's own internal estimates it
is believed that 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 Ltd. ("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 3.5 billion barrels of gross lease 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 began in 2006 and is
expected to 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.
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.
11
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.
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.
On August 17, 2006, the Company issued US$250.0 million of 10 year 6.0 per cent
unsecured notes maturing August 15, 2016 and US$450.0 million of 30 year 6.50
per cent unsecured notes maturing February 15, 2037 pursuant to a short form
base shelf prospectus dated June 3, 2005.
In November 2006, the Company completed the acquisition of Anadarko Canada
Corporation ("ACC") for net cash consideration of $4,641 million, including
working capital and other adjustments. The Company immediately integrated ACC
into its ongoing operations. The land and production base acquired are located
substantially in Western Canada and are natural gas weighted assets with a long
reserve life. The assets produce in excess of 350 mmcf/d of natural gas and
approximately 9,000 bbl/d of light crude oil and NGLs production. The assets
acquired also include approximately 1.5 million net undeveloped acres and key
strategic facilities in Northeast British Columbia and Northwest Alberta. In
conjunction with the closing of the acquisition of ACC, the Company executed a
$3,850 million, three-year non-revolving syndicated credit facility maturing in
October 2009. This facility is subject to certain prepayment requirements up to
a maximum of $1,500 million.
During 2006, the Company completed 83 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties. The
aggregate net expenditure of the transactions was $4,801 million, including the
ACC acquisition of $4,755 million. The properties acquired are located in the
Company's principal operating regions and are comprised of producing and
non-producing leases together with related facilities. As well the Company
participated in 48 transactions to dispose of non-core operated and
non-operated properties for proceeds of $68 million. Included in this amount is
a royalty disposition for $66 million.
On March 19, 2007, the Company issued US$1,100 million of 10 year 5.70 per cent
unsecured notes maturing May 15, 2017 and US$1,100 million of 30 year 6.25 per
cent unsecured notes maturing March 15, 2038 pursuant to a short form base shelf
prospectus dated November 27, 2006. Concurrently, the Company entered into
cross-currency interest-rate swaps to fix the Canadian dollar interest and
principal repayment amounts on US$1,100 million of unsecured notes due May 15,
2017 at 5.10% and C$1,287 million. The Company also entered into a
cross-currency interest-rate swap to fix the Canadian dollar interest and
principal repayment amounts on US$550 million of unsecured notes due March 15,
2038 at 5.76% and C$644 million.
12
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 primarily located in Alberta, British
Columbia, Saskatchewan, Manitoba and the Northwest and Yukon 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 and Yukon 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 NGLs, crude oil and natural gas production from 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 currently subject to
federal and provincial income taxes in Canada at a combined rate of
approximately 34.91 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
13
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 Charge Tax ("SCT") 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. During 2005, the UK Chancellor of
the Exchequer announced a further increase to the SCT of 10% to 20% on profits
from UK North Sea crude oil and natural gas production, effective January 1,
2006. In December 2006, the UK Government announced the abolition of PRT on
profits of decommissioned fields subsequently redeveloped, subject to certain
conditions being met.
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, are subject to production sharing
arrangements that provide 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 August 2006,
the Government of Cote d'lvoire announced a reduction in the rate of Corporate
Income Tax from 35 to 27 per cent, effective January 1, 2006.
In October 2005, Canadian Natural completed the acquisition of the permit to
develop the Olowi Field, offshore Gabon and received approval of its
development plan for this acquisition from the Gabonese Government in early
2006 and from Canadian Natural's Board of Directors in November 2006.
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, European 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,
14
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 2006 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.
The crude oil and natural gas industry is experiencing incremental increases in
costs related to environmental regulation, particularly in North America and
the North Sea. Existing and expected legislation and regulations will require
the Company to address and mitigate the effect of its activities on the
environment. This will include dismantling production facilities and
remediating damage caused by the disposal or release of specified substances.
Increasingly stringent laws and regulations may have an adverse effect on the
Company's future net earnings and cash flow from operations.
The Company's associated risk management strategies focus on working with
legislators and regulators to ensure that any new or revised policies,
legislation or regulations properly reflect a balanced approach to sustainable
development. Specific measures in response to existing or new legislation
include a focus on the Company's energy efficiency, air emissions management,
released water quality, reduced fresh water use and the minimization of the
impact on the landscape. The Company's strategy employs an Environmental
Management Plan known as the Stewardship Report (the "Plan"), a detailed copy
of of the Plan is presented to, and reviewed by, Health, Safety and
15
Environmental Committee of the Board of Directors annually. The Plan is updated
quarterly at the Health, Safety and Environmental Committee meetings.
The Company's Plan and operating guidelines focus on minimizing the impact of
operations while meeting regulatory requirements and internal 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:
1. The use of water-based, environmentally friendly drilling muds;
2. Implementing cost effective ways of reducing greenhouse gas emissions per
unit of production;
3. Exercising care with respect to all waste produced through effective waste
management plans; and
4. Minimizing produced water volumes onshore and offshore through
cost-effective measures.
In 2006, the Company's capital expenditures included $75 million for
abandonment expenditures, an increase from $46 million in 2005 (2004 - $32
million).
The Company's estimated undiscounted ARO at December 31, 2006 was as follows:
-------------
Estimated ARO, undiscounted ($millions) 2006 2005
-------------------------------------------------------------------------------------
North America $ 2,826 $ 2,050
North Sea 1,543 1,185
Offshore West Africa 128 90
-------------------------------------------------------------------------------------
4,497 3,325
North Sea PRT recovery (625) (370)
-------------------------------------------------------------------------------------
$ 3,872 $ 2,955
=====================================================================================
16
The estimate of the ARO is based on estimates of future costs to abandon and
restore the wells, production facilities and offshore production platforms.
Factors that affect costs include number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on
engineering estimates using current costs in accordance with present
legislation and industry operating practice. 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. The future abandonment costs incurred in the North Sea are
expected to result in an estimated PRT recovery of $625 million (2005 - $370
million), as abandonment costs are an allowable deduction in determining PRT
and may be carried back to reclaim PRT previously paid. The expected PRT
recovery reduces the Company's net abandonment liability to $3,872 million
(2005 - $2,955 million).
GREENHOUSE GAS ("GHG") AND OTHER AIR EMISSIONS
The Company is concurrently working with legislators and regulators on the
design of new greenhouse gas emission laws and regulations and is pursuing an
integrated emissions reduction strategy, to ensure the Company is able to
comply with existing and future emission reductions requirements. The Company
continues to develop strategies that will enable it to deal with the risks and
opportunities associated with new climate change policies. In addition, the
Company is working with relevant parties to ensure that new policies encourage
innovation, energy efficiency, targeted research and development while not
impacting competitiveness.
The Company continues to work with Canadian federal and provincial governments
on the regulatory framework for greenhouse gases for larger emitters. The
Company is actively promoting a harmonized regulatory framework between the two
levels of government. Both levels of government have indicated that existing
legislation will be amended in 2007 to create further requirements for
reporting emissions, facility-based emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.
Issues to be resolved include, but are not limited to: the outcome of
discussions between the Federal and Provincial Governments, the impact of
implementing legislation, the allocations of reduction obligations among
industry sectors and international developments.
Canadian Natural anticipates that changes in environmental legislation may
require, among other things, reductions in emissions to the air from its
operations. Any required reductions in the greenhouse gases emitted from the
Company's operations could increase capital expenditures and operating
expenses, especially those related to the Horizon Project and the Company's
other existing and planned large oil sands projects. This may have an adverse
effect on the Company's net earnings and cash flow from operations. Future
changes in environmental legislation could 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.
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,
17
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. The Company has developed
a comprehensive health and safety management framework to mitigate physical
risks. The Company also mitigates insurable risks to protect against
significant losses by maintaining a comprehensive insurance program, while
maintaining levels and amounts of risk within the Company which management
believes to be acceptable. However, Canadian Natural's liability, property and
business interruption insurance may not and possibly will not provide adequate
coverage in all 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.
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
18
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 crude 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, NGLs and natural gas reserves and the
future net cash flow therefrom are based upon a number of factors and
assumptions made as of the date on which the reserve estimates were determined,
such as geological and engineering estimates which have inherent uncertainties,
the assumed effects of regulation by governmental agencies and estimates of
future commodity prices and operating costs, all of which may vary considerably
from actual results. All such estimates are, to some degree, uncertain and
classifications of reserves are only attempts to define the degree of
uncertainty involved. For these reasons, estimates of the economically
recoverable crude oil, NGLs and natural gas reserves attributable to any
particular group of properties, the classification of such reserves based on
risk of recovery and estimates of future net revenues expected therefrom,
prepared by different engineers or by the same engineers at different times,
may vary substantially. Canadian Natural's actual production, revenues, taxes
and development, abandonment and operating expenditures with respect to its
reserves will likely vary from such estimates, and such variances could be
material.
Estimates with respect to reserves that may be developed and produced in the
future are often based upon volumetric calculations and upon analogy to similar
types of reserves, rather than upon actual production history. Estimates based
on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be material, in the
estimated reserves.
PRIORITY OF SUBSIDIARY INDEBTEDNESS; CONSEQUENCES OF HOLDING CORPORATION
STRUCTURE
The Company carries on business through corporate and partnership subsidiaries.
The majority of the Company's assets are held in one or more corporate or
partnership subsidiaries. The results of operations and ability to service
indebtedness, including debt securities, are dependent upon the results of
operations of these subsidiaries and the payment of funds by these subsidiaries
to the Company in the form of loans, dividends or other means employed for the
payment of funds to the Company. 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.
19
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 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.
Canadian Natural is committed to managing air emissions through an integrated
corporate approach which considers opportunities to reduce both air pollutants
and GHG emissions. Air quality programs continue to be an essential part of our
environmental work plan and are operated within all regulatory standards and
guidelines. Our strategy for managing GHG emissions is based on four core
principles: energy conservation and efficiency; reduced intensity; innovative
technology and associated research and development; and, trading capacity; both
domestically and globally.
The Company continues to implement flaring, venting and fuel and solution gas
conservation programs. In 2006 the Company completed approximately 122 gas
conservation projects, resulting in reduction of 1.24 million tonnes/year of
carbon dioxide equivalents ("CO2E"). Over the past five years the Company has
spent over $100 million to conserve the equivalent of over 5 million tonnes of
CO2E. In heavy crude oil production Canadian Natural is evaluating tank heater
efficiciencies in an effort to conserve fuel gas at facilities with field
tanks. The Company also monitors the performance of its compressor fleet and it
is continually modified and optimized for maximum efficiency. Another project
of note is the trial of "no emissions" chemical injection pumps which are
designed to eliminate fuel gas venting. These programs also influence and
20
direct the Company's plans for new projects and facilities. It is planned that
the Horizon Project will incorporate advancements in technology to reduce
further GHG emissions through maximizing heat integration, the use of
cogeneration to meet steam and electricity demands and the design of the
hydrogen production facility to enable carbon dioxide ("CO2") capture.
In its North Sea operations the Company is operating below its CO2 allocation
and continues to implement an improvement program based on efficiency audits of
its major facilities. Canadian Natural also began a Produced Water Re-injection
trial which has resulted in re-injecting approximately 30 thousand barrels of
produced water each day.
The costs incurred by the Company for compliance with environmental matters and
site restoration exceeded three per cent of the total exploration and
development expenditures incurred by the Company in each of the years ended
December 31, 2006, 2005 and 2004.
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.
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/medium 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 42 per cent of 2006 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/medium crude oil and NGLs, representing 26
per cent of 2006 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 2006 production. Other heavy crude oil, which accounts for
five per cent of 2006 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 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 are expected to deliver approximately 37 years of
synthetic crude oil production.
21
As a result of the Company's core undeveloped land base of 12.8 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.
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, 2006. The information reflects the working
interests owned by the Company.
YEAR ENDED
2006 AVERAGE DAILY DECEMBER 31, MAJOR INFRASTRUCTURE
PRODUCTION RATES 2006 AS AT DECEMBER 31, 2006
--------------------- ---------------- -------------------------
CRUDE BATTERIES/
OIL & NATURAL UNDEVELOPED COMPRESSORS & PLANTS/
NGLs GAS ACREAGE PLATFORMS
REGION (mbbl) (mmcf) (thousands) /FPSO
NORTH AMERICA
Northeast B. C. 6.7 408 2,721 1/11/-/-
Northwest Alberta 15.0 454 1,750 -/14/-/-
Northern Plains 194.5 437 7,211 12/6/-/-
Southern Plains 10.5 165 870 -/3/-/-
Southeast 8.4 3 117 -/-/-/-
Saskatchewan
Non - core regions 0.2 1 249 -/-/-/-
Horizon Oil Sands - - 116 -/-/-/-
INTERNATIONAL
North Sea UK Sector 60.1 15 299 -/-/6/1
Offshore West Africa
Cote d'Ivoire 36.7 9 55 -/-/-/2
Gabon - - 152 -/-/-/-
Non - core regions
South Africa - - 4,002 -/-/-/-
-----------------------------------------------------------------------------------------------
TOTAL 332.1 1,492 17,542 13/34/6/3
===============================================================================================
22
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
ending December 31, 2006 by geographic region:
2006
-------------------------------------------------------------------------------------------------------------------------
NET EXPLORATORY NET DEVELOPMENT
PRODUCTIVE DRY HOLES TOTAL PRODUCTIVE DRY HOLES TOTAL
-------------------------------------------------------------------------------------------------------------------------
CANADA
17.2 5.6 22.8 158.9 14.1 173.0
Northeast B. C.
17.7 9.5 27.2 149.6 14.6 164.2
Northwest Alberta
104.1 28.2 132.3 598.5 36.1 634.6
Northern Plains
31.8 8.4 40.2 78.6 1.0 79.6
Southern Plains
- - - 72.7 2.0 74.7
Southeast Saskatchewan
0.6 - 0.6 2.7 - 2.7
Non - core regions
NORTH SEA UK SECTOR - - - 7.4 - 7.4
OFFSHORE WEST AFRICA
Cote d'Ivoire - - - 4.1 - 4.1
-------------------------------------------------------------------------------------------------------------------------
TOTAL 171.4 51.7 223.1 1,072.5 67.8 1,140.3
=========================================================================================================================
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 1,339.7 83.2 1,422.9
=========================================================================================================================
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
=========================================================================================================================
23
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, 2006:
-----------------------------------------------------------------------------------------------------------------------
NATURAL GAS WELLS CRUDE OIL WELLS TOTAL WELLS
GROSS NET GROSS NET GROSS NET
-----------------------------------------------------------------------------------------------------------------------
CANADA
Northeast B. C. 1,548.0 1,305.5 243.0 203.5 1,791.0 1,509.0
Northwest Alberta 1,681.0 1,294.7 521.0 305.9 2,202.0 1,600.6
Northern Plains 4,022.0 3,233.4 5,705.0 5,204.6 9,727.0 8,438.0
Southern Plains 6,955.0 5,986.9 1,140.0 1,032.0 8,095.0 7,018.9
Southeast Saskatchewan - - 1,092.0 694.8 1,092.0 694.8
Non - core regions 316.0 118.6 665.0 202.1 981.0 320.7
UNITED STATES 4.0 0.5 4.0 0.7 8.0 1.2
NORTH SEA UK SECTOR 2.0 0.1 118.0 96.8 120.0 96.9
OFFSHORE WEST AFRICA
Cote d'Ivoire 0.0 0.0 15.0 8.7 15.0 8.7
-----------------------------------------------------------------------------------------------------------------------
TOTAL 14,528.0 11,939.7 9,503.0 7,749.1 24,031.0 19,688.8
=======================================================================================================================
All reserves data in the following property report is based on the applicable
independent engineering report. See below "Conventional Crude Oil, NGLs and
Natural Gas Reserves" and "Oil Sands Mining Disclosure".
NORTHEAST BRITISH COLUMBIA
[GRAPHIC OMITTED - MAP]
Significant geological variation extends throughout the productive reservoirs
in region, producing light crude oil, NGLs and natural gas. The Company holds
working interests ranging up to 100 per cent and averaging 74 per cent in
5,107,623 gross (3,721,424 net) acres of producing and undeveloped land in the
region.
24
Crude oil reserves are found primarily in the Halfway formation, while natural
gas and associated NGLs are found in numerous carbonate and sandstone
formations at depths up to 4,500 vertical meters. The exploration strategy
focuses on comprehensive evaluation through two-dimensional seismic,
three-dimensional seismic and targeting economic prospects close to existing
infrastructure. The region has a mix of low risk multi-zone targets, deep
higher risk exploration plays and emerging unconventional natural gas plays
including shale gas and CBM. The 2006 acquisition of ACC significantly
increases the Company's asset base in Northeast British Columbia with the
addition of the ACC properties in Adsett, Caribou and Ft. St. John West. The
southern portion of this region encompasses the Company's BC Foothills assets;
here natural gas is produced from the deep Mississippian and Triassic aged
reservoirs in this highly deformed structural area. In 2006 the Company's
assets in Monkman and Ojay were augmented by the assets previously owned by ACC
in the area.
Natural gas production from the region averaged 408 mmcf/d in 2006 compared to
the average of 434.4 mmcf/d in 2005. Crude oil and NGLs production was steady
at 6,700 bbl/d in 2006, unchanged from an average of 6,700 bbl/d in 2005.
During 2005, the Company initiated a new exploration and development play 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 mmcf/d. 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.
Development of this play continued in 2006 with the drilling of 45 wells at
Ladyfern. Another shallow gas play was pursued in 2006 with the drilling of 50
Banff wells at Shekelie.
During 2006, the Company drilled 12.9 (2005 - 10.9) net crude oil wells, 163.2
(2005 - 201.1) net natural gas wells, 0.0 (2005 - 1.0) net
stratigraphic/service wells and 19.7 (2005 - 28.3) net dry wells on its lands
in this region for a total of 195.8 (2005 - 241.3) net wells. The Company held
an average 86 per cent working interest in these wells.
NORTHWEST ALBERTA
[GRAPHIC OMITTED - MAP]
25
The Company holds working interests ranging up to 100 per cent and averaging 73
per cent in 3,537,210 gross (2,582,042 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 initial holdings in the region were obtained
through the 2002 acquisition of RAX; subsequent to 2002 the Company augmented
these holdings with additional land purchases, acquisitions and in 2006 the
purchase of the ACC assets. The ACC acquisition added two very prospective
properties to this region, Wild River and Peace River Arch. The Wild River
assets will provide a premium developed and undeveloped land base in the deep
basin, multi-zone gas fairway and the Peace River Arch assets provides premium
lands in a multi-zone region along with key infrastructure. Northwest Alberta
provides exploration and exploitation opportunities in combination with an
extensive 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 region provides extensive multi-zone Cretaceous
opportunities similar to the geology of the Company's Northern Plains core
region. The Company is also pursuing development of a Doig shale gas play in
this region. The southern portion provides exploration and development
opportunities in the regionally extensive Cretaceous Cardium formation and in
the deeper, tight gas formations throughout the region. The Cardium is a
complex, tight natural gas reservoir where high productivity may be achieved
due to greater matrix porosity or natural fracturing. Recent regulatory changes
have improved the economics of multi-zone production by providing the
opportunity to commingle multiple zones within a single wellbore. The south
western portion of this region also contains significant Foothills assets with
natural gas produced from the deep Mississippian and Triassic aged reservoirs.
In 2006 Canadian Natural had significant success in this Foothills region with
drilling successes at Copton, Dinosaur and Cabin Creek.
Natural gas production from the region averaged 454 mmcf/d in 2006 compared to
an average of 403.4 mmcf/d in 2005. Crude oil and NGLs production increased to
15.0 thousand bbl/d in 2006 from 13.5 thousand bbl/d in 2005.
During 2006, the Company drilled 14.5 (2005-12.9) net crude oil wells, 152.8
(2005-152.4) net natural gas wells, 0.0 (2005 - 0.7) net stratigraphic/service
wells, and 24.1 (2005-16.3) net dry wells on its lands in this region for a
total of 191.4 (2005-182.3) net wells. The Company held an average 72 per cent
working interest in these wells.
NORTHERN PLAINS
[GRAPHIC OMITTED - MAP]
26
The Company holds working interests ranging up to 100 per cent and averaging 83
per cent in 12,781,313 gross (10,711,563 net) acres of producing and
undeveloped land in the region located just south of Edmonton north to Fort
McMurray and from the Northwest Alberta area 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 437 mmcf/d in 2006 compared to 419.2 mmcf/d in
2005. Crude oil and NGLs production from this region increased to 194.5
thousand bbl/d in 2006 from 181.8 thousand bbl/d in 2005. 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.
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 Horseshoe Canyon CBM project. During 2006,
natural gas development drilling included 120.5 net wells and 48.0 net
Horseshoe Canyon CBM locations. Evaluation of the potential for production of
CBM from the Mannville coals commenced in 2006 with the drilling of three
horizontal wells; these wells will be tested and produced to determine the
economic viability of this play.
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.
The Company's holdings in this region of primary heavy oil production are both
the result of Crown land purchases and several acquisitions including major
acquisitions from Sceptre Resources, Koch Exploration, Ranger Oil and
Petrovera. 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
and to the Morgan field in 2006 enhancing development and reducing operating
costs for 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
27
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 heavy (10(Degree)-11(Degree)API) 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. Since acquiring the assets from BP Amoco in 2000, the Company has
successfully converted the field from low-pressure steaming to high-pressure
steaming. This conversion resulted in a significant improvement in well
productivity and in ultimate oil recovery. Canadian Natural drilled 58
high-pressure wells in 2004. In 2004, the Company started to proceed with its
Primrose North expansion project, which was effectively completed in late 2005
with total capital expenditures of approximately $300 million incurred. The
Primrose North expansion entails a remote steam generation facility and
additional high pressure cyclic steam 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 for Primrose East 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 received regulatory approval for the project in
February, 2007 and construction will begin in 2007, with the first steam
injection scheduled for first quarter 2009. A mature 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. In December 2006 Canadian Natural issued a
Public Disclosure Document outlining our proposed development plan for the 30
thousand bbl/d Kirby In-Situ Oil Sands Project located approximately 85 km
northeast of Lac La Biche. Regulatory applications for the project are expected
to be submitted in late 2007.
In 2006 the Company undertook a Scoping Study to evaluate the construction of
an upgrader to process the Company's Athabasca and Cold Lake thermal
production. The study included evaluating the product alternatives, location,
technology, gasification and integration with existing assets. The next steps
in this process would include a Design Base Memorandum ("DBM") and Engineering
Design Specifications ("EDS") which would be required to be completed prior to
construction and sanctioning of the project by the Board of Directors of the
Company. Based upon the results of the Scoping Study, which identified growing
concerns relating to increased environmental costs for upgraders located in
Canada, inflationary capital cost pressures and narrowing heavy oil
differentials in North America, the Company has, at this point in time,
deferred the DBM and EDS pending clarification on the cost of future
environmental legislation and a more stable cost environment.
Included in the northern part of this region, approximately 200 miles north of
Edmonton, are the Company's holdings at Pelican Lake. These assets produce
crude oil from the Wabasca formation with gravities of 11(Degree)-17(Degree)
28
API. Production costs are low due to the absence of sand production, its
associated 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 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.
It is estimated this field contains approximately four billion barrels of
original crude oil in place but is only expected to achieve less than a five
percent average recovery factor using existing primary production 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 date
approximately 11% of the field has been converted to waterflood. To further
enhance the expected crude oil recovery from the waterflood, in the second
quarter of 2005, the Company initiated a five well polymer flood pilot test.
Performance of the polymer flood pilot test has been positive, with crude oil
production rates from the three production wells increasing from approximately
60 bbl/d in 2005 to over 500 bbl/d by December 2006. These results have led to
the commercial expansion of this EOR technology with 36 additional wells
undergoing polymer flooding by year end 2006. Pelican Lake production averaged
approximately 30 thousands bbl/d in 2006.
During 2006, the Company drilled 484.0 (2005 - 536.1) net crude oil wells,
218.6 (2005 - 198.9) net natural gas wells, 206.9 (2005 - 108.9) net
stratigraphic/service wells, and 64.3 (2005 - 63.4) net dry wells for a total
of 973.8 (2005 - 907.3) net wells. The Company's average working interest in
these wells was 88.4 per cent.
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN
[GRAPHIC OMITTED - MAP]
In the Southern Plains area, the Company holds interests ranging up to 100 per
cent and averaging 86 per cent in 2,147,945 gross (1,838,811 net) acres of
producing and undeveloped land in the region, principally located south of the
Northern Plains area to the United States border and extending into western
Saskatchewan.
29
Reserves of natural gas, condensate and light 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. It is economic to drill shallow wells with reduced well
spacings in this region despite having smaller overall reserves and lower
productivity per well since they achieve a favourable rate of return on capital
employed with low drilling costs and long life reserves. The Company's
extensive shallow gas assets in this region have been augmented in 2006 as a
result of the Company's development of the Senate shallow gas play in SW
Saskatchewan and the purchase of the ACC Hatton assets in SW Saskatchewan.
Other assets acquired from ACC in this region include the crude oil producing
assets at Taber.
The Company maintains a large inventory of drillable locations on its land base
in this region. This region is one of the more mature regions 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 10.5
thousand bbl/d of crude oil and NGLs compared to 10.7 thousand bbl/d in 2005.
Natural gas production amounted to 165 mmcf/d in 2006 compared to the 155.4
mmcf/d averaged in 2005.
During 2006, the Company drilled a total of 6.2 (2005 - 9.0) net crude oil
wells, 104.2 (2005 - 336.5) net natural gas wells, 0.0 (2005 - 1.7) net
stratigraphic/service wells and 9.4 (2005 - 7.0) net dry wells in this region
for a total of 119.8 (2005 - 354.2) net wells. The Company's average working
interest in these wells was 57.3 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 82 per cent in 220,266 gross (181,691 net) acres of
producing and undeveloped lands in the region.
The region produces primarily light sour crude oil from as many as seven
productive horizons found at depths up to 2,700 meters. The Company's share of
production in the Southeast Saskatchewan area averaged 8,400 bbl/d of crude oil
and NGLs in 2006 compared to 8,800 bbl/d in 2005. Natural gas production
averaged 3 mmcf/d in 2006 (2005 - 3.1 mmcf/d).
The Company drilled 72.7 (2005 - 43.0) net crude oil wells, 0.0 (2005 - 1.0)
net natural gas well, 0.0 (2005 - 7.6) net stratigraphic/service wells and 2.0
(2005 - 0.0) net dry wells in this region in 2006, for a total of 74.7 (2005 -
51.6) net wells. The Company's average working interest in these wells is 86.9
per cent.
30
HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED - MAP]
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 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 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 is
planned to 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. Subsequent
expansion is expected to increase production to 232 thousand bbl/d of SCO.
These targeted rates of production represent nominal design capacity. The
Company is currently evaluating the opportunity to combine Phase 2 and Phase 3,
for which certain major items were ordered in 2006 and certain major facility
components had construction commence on them in 2006. 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.
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.
The Company is concurrently working with legislators and regulators on the
design of new greenhouse gas emission laws and regulations and is pursuing an
integrated emissions reduction strategy, to ensure the Company is able to
comply with existing and future emission reductions requirements. The Company
continues to develop strategies that will enable it to deal with the risks and
opportunities associated with new climate change policies. In addition, the
Company is working with relevant parties to ensure that new policies encourage
31
innovation, energy efficiency, targeted research and development while not
impacting competitiveness.
The Company continues to work with Canadian Federal and Provincial governments
on the regulatory framework for greenhouse gases for larger emitters. The
Company is actively promoting a harmonized regulatory framework between the two
levels of government. Both levels of government have indicated that existing
legislation will be amended in 2007 to create further requirements for
reporting emissions, facility-based emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.
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 Company is now developing various cost effective
options for execution of additional construction on Phase 2 and Phase 3 of the
Horizon Project taking into account the current business environment.
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 production costs. By the end of 2004 the Company had
acquired all key technologies for the project. At year end 2006, Canadian
Natural's Horizon Project team, consisted of 705 permanent employees and
several interim contractors to fill 79% of the projected team position
requirements.
Horizon Project Phase 1 construction costs were approximately $2.77 billion in
2006 and cumulative expenditures were approximately $4.0 billion through the
end of 2006. Construction costs for 2007 are budgeted to range from $2.4
billion to $2.8 billion reflecting major expenditures for detailed engineering,
procurement and construction of Phase 1 of the Project. In addition, capital
expenditures of $109 million are budgeted for Phase 2 and Phase 3 development
and construction in 2007. These expenditures are direct project costs only and
do not include capitalized interest, stock based compensation, lease
evaluation, or Front End Engineering.
During 2006, the Company drilled 163.0 (2005 - 126.0) stratigraphic test wells
to further delineate the ore body and confirm resource quality and quantity.
32
UNITED KINGDOM NORTH SEA
[GRAPHIC OMITTED - MAPS]
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 367,251 gross (296,658 net) acres of producing and non-producing
properties in the UK sector of the North Sea. In 2006, 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 resulted in lower combined production costs from these
fields.
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
33
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 2006, production to the Company from this region averaged 60.1 thousand
bbl/d of crude oil (2005 - 68.6 thousand bbl/d). Natural gas production
averaged 15.0 mmcf/d in 2006 (2005 - 18.4 mmcf/d).
During 2006 the Company drilled 7.4 (2005 - 11.5) net crude oil wells, 1.8
(2005 - 0.9) net stratigraphic/service wells and 0.0 (2005 - 1.7) net dry wells
in this region for a total of 9.2 (2005 - 14.1) net wells. The Company's
average working interest in these wells is 92.0 per cent.
OFFSHORE WEST AFRICA
[GRAPHIC OMITTED - MAP]
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. As a result, the Company owned working interests
ranging from 50 per cent to 100 per cent in 1,596,013 gross (887,657 net) acres
in those countries. During 2005, the Company either relinquished or sold all of
its interests in offshore Angola. In 2006, certain exploration acreage in Cote
d'Ivoire was also relinquished.
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.
COTE D'IVOIRE
The Company owns interests in two exploration licences offshore Cote d'Ivoire
comprising 55,408 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
34
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 included 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. Due to a successful infill drilling
program completed at East Espoir in early 2006 the Company achieved 24.0
thousand bbl/d of net production from the Field. Following the infill drilling
at East Espoir, development drilling commenced at West Espoir with first oil
from the Field delivered July, 2006.
Crude oil from the East and West Espoir Fields is produced to an FPSO with the
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 increased as expected.
Subsequent problems with the control of sand and solids production lead to five
of the ten production wells being shut in by the end of the year, resulting in
approximately 15.5 thousand bbl/d of net production capacity being shut in. The
Company does not plan to complete these wells until such time as a deepwater
rig can be secured on commercially acceptable terms.
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 2006, Company production averaged 36.7 thousand bbl/d of crude oil (2005
- 22.9 thousand bbl/d). Company natural gas production amounted to 9.5 mmcf/d
in 2006 (2005 - 4.2 mmcf/d).
In 2006, the Company drilled 4.1 (2005 - 3.5) net crude oil wells, 1.7 (2005 -
1.1) net stratigraphic/service wells and 0.0 (2005 - 0.6) net dry wells for a
total of 5.8 (2005 - 5.2) net wells. The Company's average working interest in
these wells is 58.7 per cent.
ANGOLA
During 2002, the Company was awarded operatorship and a 50 per cent working
interest in exploration Block 16 situated offshore The People's Republic of
Angola. 3-D seismic 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 had a two well commitment over a four
year time frame expiring August 31, 2006. The first well, Zenza-1, was drilled
35
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 indicated
that significant upside remained a possibility, the risk level associated with
Block 16 was 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 - MAP]
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. Based on estimates from the previous owner it was estimated that the
properties held 500 million barrels of original oil in place and 1 trillion
cubic feet of original gas in place. Subsequent to acquiring the assets and all
technical data, the Company performed a detailed analysis on the geological,
geophysical and engineering data and has reestimated the pool size. The
Company's internal estimates for Olowi are that the pool contains up to 215
million barrels of 34(0) API light crude original oil in place, with an
underlying gas cap containing up to 590 billion 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 plan for the pool commenced in late 2006 and first production
is targeted for late 2008.
36
B. CONVENTIONAL CRUDE OIL, NGL, AND NATURAL GAS RESERVES
For the year ended December 31, 2006, 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 as well as 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 (i) the 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; and, (ii) the definition
of proved reserves used by the SEC to that of NI 51-101. However with respect
to the definition of proved reserves, 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
should not be 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.
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, 2006.
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. NO INDIRECT
COSTS SUCH AS OVERHEAD, INTEREST AND ADMINISTRATIVE EXPENSES HAVE BEEN DEDUCTED
FROM THE ESTIMATED FUTURE NET REVENUES. OTHER ASSUMPTIONS AND QUALIFICATIONS
RELATING TO COSTS, PRICES FOR FUTURE PRODUCTION AND OTHER MATTERS ARE
SUMMARIZED IN THE NOTES TO THE FOLLOWING TABLES. THERE IS NO ASSURANCE THAT THE
PRICE AND COST ASSUMPTIONS CONTAINED IN EITHER THE CONSTANT OR FORECAST CASES
WILL BE ATTAINED AND VARIANCES COULD BE SUBSTANTIAL.
37
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 887 1,502 3,703 4,855
United States - - 2 2
INTERNATIONAL
United Kingdom 299 422 37 93
Cote d'Ivoire 115 173 56 99
Gabon 15 22 - -
------------------------------------- -----------------------------------
------------------------------------- -----------------------------------
TOTAL 1,316 2,119 3,798 5,049
===================================== ===================================
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 779 697 3,619 2,963
Proved undeveloped reserves 708 619 994 835
------------------------------------- -----------------------------------
TOTAL PROVED RESERVES 1,487 1,316 4,613 3,798
TOTAL PROVED AND PROBABLE
RESERVES 2,397 2,119 6,112 5,049
===================================== ===================================
ESTIMATED NET PRESENT VALUES
($ millions) Constant Prices and Costs
---------------------------------------------------------------------------
Undiscounted Discounted at
10% 15% 20%
---------------------- ------------------------------------------------
Proved developed reserves 31,286 20,028 17,296 15,321
Proved undeveloped reserves 17,974 7,469 5,247 3,787
---------------------- ----------------- ------------ ------------
TOTAL PROVED RESERVES 49,260 27,497 22,543 19,108
TOTAL PROVED AND PROBABLE
RESERVES 75,787 37,291 29,350 24,102
====================== ================= ============ ============
38
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 771 698 3,643 2,982
Proved undeveloped reserves 706 633 994 831
------------------- -------------- ------------ ------------
TOTAL PROVED RESERVES 1,477 1,331 4,637 3,813
TOTAL PROVED AND PROBABLE
RESERVES 2,540 2,294 6,141 5,067
=================== ============== ============ ============
ESTIMATED NET PRESENT VALUES
($ millions) Forecast Prices and Costs
---------------------------------------------------------------------------
Undiscounted Discounted at
10% 15% 20%
---------------------- ------------------------------------------------
Proved developed reserves 33,483 21,734 18,975 16,973
Proved undeveloped reserves 17,446 7,410 5,267 3,856
---------------------- ----------------- ------------- ------------
TOTAL PROVED RESERVES 50,929 29,144 24,242 20,829
TOTAL PROVED AND PROBABLE
RESERVES 78,155 38,896 30,883 25,604
====================== ================= ============= ============
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 using forecast
prices and costs as well as before royalties and their associated net
present values 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 using forecast prices and costs as well as before
royalties and their associated net present values 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 using forecast prices and costs
as well as before royalties and their associated net present values 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 using both constant prices and costs as well as
forecast prices and costs and has disclosed these before and net of
royalties and their associated net present values. The calculation of a
probable reserves and value component by subtracting the proved reserves
from the proved plus probable reserves may be subject to immaterial error
due to the different standards applied in the determination of each
value.
7. Canadian securities legislation and policies permit the disclosure, of
probable reserves which may not be disclosed in reports filed with the
SEC by United States companies. 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.
39
9. The constant price and cost case assumes that prices in effect at
year-end 2006 adjusted for quality and transportation as well as the 2006
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 2007 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 (based on a foreign exchange rate of
US$0.860/C$1.00):
NATURAL GAS CRUDE OIL & NGLs
-------------------------------------------------- ----------------------------------------------
Company Company Hardisty Edmonton North
Average Henry Hub Huntingdon/ Average WTI @ Heavy Par(ii) Sea
Price Louisiana AECO Sumas Price Cushing(i) 12(degree) API Brent
YEAR C$/MCF US$/MMBTU C$/MMBTU C$/MMBTU C$/BBL US$/BBL C$/BBL C$/BBL US$/BBL
---- ------ --------- --------- -------- ------ ------- ------ ------ -------
2007 6.07 5.52 6.13 6.52 51.11 61.05 41.94 67.59 58.93
(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.
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, 2006 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 2006 were $51.11 per barrel and $6.07 per
mcf respectively, before adjustments due to hedging. The crude oil and
natural gas forecast prices used in the Evaluation Reports are as
follows:
------------------------------------------------------------------------------------------------------------
NATURAL GAS CRUDE OIL & NGLs
--------------------------------------------------- ---------------------------------------------------
Company Company Hardisty Edmonton North
Average Henry Hub Huntingdon/ Average WTI @ Heavy Par(ii) Sea
Price Louisiana AECO Sumas Price Cushing(i) 12(degree) API Brent
YEAR C$/MCF US$/MMBTU C$/MMBTU C$/MMBTU C$/BBL US$/BBL C$/BBL C$/BBL US$/BBL
---- ------ --------- --------- -------- ------ ------- ------ ------ -------
2007 7.57 7.85 7.72 7.48 53.95 65.73 42.98 74.10 63.73
2008 8.45 8.39 8.59 8.45 56.07 68.82 45.02 77.62 66.78
2009 7.58 7.65 7.74 7.60 52.36 62.42 40.74 70.25 60.34
2010 7.35 7.48 7.55 7.41 48.60 58.37 38.03 65.56 56.24
2011 7.49 7.63 7.72 7.58 45.62 55.20 35.90 61.90 53.04
2012 7.64 7.75 7.85 7.71 47.26 56.31 36.63 63.15 54.10
2013 7.80 7.86 7.99 7.85 47.45 57.43 37.36 64.42 55.18
2014 7.97 7.98 8.12 7.98 48.75 58.58 38.12 65.72 56.29
2015 8.13 8.10 8.26 8.12 49.55 59.75 38.88 67.04 57.41
2016 8.27 8.22 8.40 8.26 48.95 60.95 39.67 68.39 58.56
2017 8.43 8.34 8.54 8.40 50.25 62.17 40.46 69.76 59.73
(i) Foreign exchange rate used was US$0.870/C$1.00 throughout the
forecast
11. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and NGLs, less all capital
costs, production taxes, and operating costs and before provision for
income taxes, administrative overhead costs and existing asset
abandonment liabilities.
40
12. The estimated total development capital costs net to the Company
necessary to achieve the estimated future net "proved" and "proved and
probable" production revenues are:
PROVED PROVED AND PROBABLE
----------------------------------------------------------------------------------------------
FORECAST PRICE CASE CONSTANT PRICE CASE FORECAST PRICE CASE CONSTANT PRICE CASE
($ millions) ($ millions) ($ millions) ($ millions)
------------ ------------ ------------ ------------
2007 1,781 1,783 2,138 2,097
2008 1,555 1,615 2,275 2,040
2009 1,819 1,718 2,561 2,054
2010 915 841 2,096 1,479
2011 838 745 1,764 1,294
2012 420 370 630 549
2013 281 251 601 510
2014 344 299 709 603
2015 197 172 602 500
2016 193 168 418 341
2017 115 102 346 220
2018 215 180 424 332
Thereafter 1,143 919 2,317 1,694
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 Schedule "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.
41
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, 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
----------------------------------------------- ------------------------------------------------
Extensions & Discoveries 53 3 - 56 250 - - 250
Infill Drilling 190 14 - 204 71 - - 71
Improved Recovery - 12 - 12 3 - - 3
Property purchases 26 - - 26 1,111 - - 1,111
Property disposals - - - - (1) - - (1)
Production (75) (22) (13) (110) (433) (5) (3) (441)
Revisions of prior estimates (1) 2 9 10 (37) 13 (13) (37)
----------------------------------------------- ------------------------------------------------
RESERVES, DECEMBER 31, 2006 887 299 130 1,316 3,705 37 56 3,798
----------------------------------------------- ------------------------------------------------
PROVED AND PROBABLE RESERVES
----------------------------------------------- ------------------------------------------------
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
----------------------------------------------- ------------------------------------------------
Extensions & Discoveries 128 3 - 131 307 - - 307
Infill Drilling 384 17 - 401 95 - - 95
Improved Recovery - 12 - 12 4 - - 4
Property purchases 34 - - 34 1,466 - - 1,466
Property disposals - - - - (1) - - (1)
Production (75) (22) (13) (110) (433) (5) (3) (441)
Revisions of prior estimates (4) (5) 2 (7) (129) 29 (8) (108)
----------------------------------------------- ------------------------------------------------
RESERVES, DECEMBER 31, 2006 1,502 422 195 2,119 4,857 93 99 5,049
----------------------------------------------- ------------------------------------------------
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 Form 40-F filed with
the SEC and in the Company's 2006 Annual Report under "Supplementary Oil and
Gas Information" on pages 99 to 103 and is incorporated herein by reference.
42
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 and is
targeted to to reach 232 thousand bbl/d with future expansion. 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.
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
lease proved and probable reserves associated with the Horizon Project are 3.0
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.
43
FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED - MAPS]
TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES
--------------------------------------------------------------------------------
SHORT LEASE NAME OFFICIAL LEASE LEASE AREA IN
NUMBER EXPIRY DATE(1) HECTARES
================================================================================
Lease 18 727912T18 Continued 19,988
Producing(2)
--------------------------------------------------------------------------------
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.
44
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
Alberta Energy and Utilities Board ("EUB"), 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).
45
As of year-end 2006, key development achievements associated with the Horizon
Project were as follows:
o Phase 1 is 57 per cent complete.
o Mine overburden has removed 25.1 million bank cubic meters of
material.
o Majority of foundations are complete.
o Main Piperack on site and set.
o Coke drums transported and erected.
o Hydrotreating reactors erected.
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 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 five meters. Locally, this member may be entirely
eroded. Exceptional thickness of about 15 meters can be found within the upper
46
McMurray. In most cases, the bitumen saturation in the upper McMurray is poor
and the material is included with the overburden.
FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED]
HORIZON OIL SANDS PROJECT MINING RESERVES
For the year ended December 31, 2006, 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, NGLs and natural gas reserves.
The pit limits and mine plans were updated in 2006 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 3.0 billion barrels of gross
lease 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.
47
FIGURE 3 - HORIZON OIL SANDS PROJECT RESOURCE AREAS AND GENERAL LAYOUT
[GRAPHIC OMITTED - PLOT MAP]
48
FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE
[GRAPHIC OMITTED - PLOT MAP]
49
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, 2006:
Constant Prices
-----------------------------------------------------------------------------
Bitumen (mmbbl) Synthetic Crude Oil (1) (mmbbl)
Gross Lease (2) Net Gross Lease (2) Net
------------------------------------ -------------------------------------
Total proved reserves 2,275 1,853 1,866 1,596
Total proved and probable reserves 3,530 2,872 2,962 2,542
(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 Lease reserves are the total remaining recoverable reserves on the
Lease 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
-------------------------------------------------------
2006 2005 2004
---- ---- ----
Daily Production, before royalties
Crude Oil and NGLs (bbl/d) 331,998 313,168 282,489
Natural Gas (mmcf/d) 1,492 1,439 1,388
Annual Production, before royalties
Crude Oil and NGLs (mbbl) 121,179 114,306 103,391
Natural Gas (bcf) 545 525 508
50
NETBACKS
INFORMATION BY QUARTER
YEAR 2006 YEAR 2005
----------------------------------------- ------------------------------------------
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) 323,662 338,852 321,665 343,705 331,998 287,803 289,064 334,724 340,268 313,168
Natural Gas (mcf/d) 1,436 1,475 1,437 1,620 1,492 1,455 1,454 1,423 1,423 1,439
PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
Sales Price (1) 43.79 60.05 62.55 47.27 53.65 $ 39.81 $ 42.51 $ 57.35 $ 46.38 $ 46.86
Royalties 3.48 5.14 5.11 4.10 4.48 $ 3.39 $ 3.33 $ 5.11 $ 3.89 $ 3.97
Production Expenses 11.33 11.92 13.47 12.32 12.29 $ 11.30 $ 11.66 $ 11.48 $ 10.33 $ 11.17
NETBACK 28.98 42.99 43.97 30.85 36.88 $ 25.12 $ 27.52 $ 40.76 $ 32.16 $ 31.72
Natural Gas ($mcf)
Sales Price (1) 8.30 6.16 5.83 6.66 6.72 $ 6.68 $ 7.33 $ 8.61 $ 11.67 $ 8.57
Royalties 1.70 1.11 1.11 1.26 1.29 $ 1.30 $ 1.48 $ 1.93 $ 2.30 $ 1.75
Production Expenses 0.80 0.80 0.84 0.86 0.82 $ 0.69 $ 0.71 $ 0.76 $ 0.76 $ 0.73
NETBACK 5.80 4.25 3.88 4.54 4.61 $ 4.69 $ 5.14 $ 5.92 $ 8.61 $ 6.09
Light/Pelican Lake/NGLs
($/bbl)
Sales Price (1) 58.28 69.02 71.65 57.68 64.33 $ 53.14 $ 56.85 $ 66.81 $ 58.87 $ 59.16
Royalties 4.65 5.53 5.39 4.39 5.00 $ 5.20 $ 4.55 $ 5.50 $ 4.40 $ 4.90
Production Expenses 11.15 11.18 14.12 12.99 12.42 $ 11.58 $ 12.28 $ 11.47 $ 8.90 $ 10.93
NETBACK 42.48 52.31 52.14 40.30 46.91 $ 36.36 $ 40.02 $ 49.84 $ 45.57 $ 43.33
Heavy Crude Oil ($/bbl)
Sales Price (1) 25.22 50.08 51.38 36.11 41.20 $ 25.21 $ 27.82 $ 47.25 $ 30.27 $ 33.09
Royalties 1.98 4.71 4.76 3.78 3.88 $ 1.41 $ 2.07 $ 4.83 $ 3.08 $ 2.92
Production Expenses 11.55 12.73 12.67 11.60 12.15 $ 11.00 $ 11.03 $ 11.50 $ 12.18 $ 11.44
NETBACK 11.69 32.64 33.95 20.73 25.17 $ 12.80 $ 14.72 $ 30.92 $ 15.01 $ 18.73
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) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
51
NETBACKS
INFORMATION BY QUARTER
YEAR 2004
-------------------------------------------------------
1ST 2ND 3RD 4TH YEAR
QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- -----
Average Daily Production Volumes
Crude oil and NGLs (bbl/d) 261,286 275,398 297,262 295,704 282,489
Natural Gas (mcf/d) 1,294 1,452 1,396 1,410 1,388
PRODUCT NETBACKS
Crude oil and NGLs ($/bbl)
Sales Price (1) $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99
Royalties $ 2.91 $ 3.15 $ 3.59 $ 2.95 $ 3.16
Production Expenses $ 9.58 $ 9.92 $ 10.21 $ 10.41 $ 10.05
NETBACK $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78
Natural Gas ($/mcf)
Sales Price (1) $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50
Royalties $ 1.27 $ 1.38 $ 1.39 $ 1.34 $ 1.35
Production Expenses $ 0.65 $ 0.66 $ 0.71 $ 0.68 $ 0.67
NETBACK $ 4.39 $ 4.60 $ 4.14 $ 4.75 $ 4.48
CRUDE OIL AND NGLS NETBACKS BY TYPE
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $ 40.75 $ 45.28 $ 51.54 $ 48.60 $ 46.71
Royalties $ 3.71 $ 3.98 $ 3.99 $ 4.12 $ 3.95
Production Expenses $ 9.77 $ 10.36 $ 10.70 $ 11.20 $ 10.53
NETBACK $ 27.27 $ 30.94 $ 36.85 $ 33.28 $ 32.23
Heavy Crude Oil ($/bbl)
Sales Price (1) $ 27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99
Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
NETBACK $ 15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09
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) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
52
NETBACKS
INFORMATION BY QUARTER
YEAR 2006 YEAR 2005
----------------------------------------- ------------------------------------------
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) $48.83 $64.35 $65.15 $48.47 $56.52 $45.80 $49.78 $61.21 $52.10 $52.35
Royalties $ 8.98 $10.87 $10.86 $ 7.80 $ 9.59 $10.64 $ 8.77 $11.49 $ 9.62 $10.13
Production Expenses $ 9.86 $ 9.75 $10.81 $13.18 $10.93 $ 8.30 $ 8.40 $ 9.27 $ 8.60 $ 8.65
NETBACK $29.99 $43.73 $43.48 $27.49 $36.00 $26.86 $32.61 $40.45 $33.88 $33.57
Heavy Crude Oil ($/bbl)
Sales Price (1) $25.22 $50.08 $51.38 $36.11 $41.20 $25.21 $27.82 $47.25 $30.27 $33.09
Royalties $ 1.98 $ 4.71 $ 4.76 $ 3.78 $ 3.88 $ 1.41 $ 2.07 $ 4.83 $ 3.08 $ 2.92
Production Expenses $11.55 $12.73 $12.67 $11.60 $12.15 $11.00 $11.03 $11.50 $12.18 $11.44
NETBACK $11.69 $32.64 $33.95 $20.73 $25.17 $12.80 $14.72 $30.92 $15.01 $18.73
Natural Gas ($/mcf)
Sales Price (1) $ 8.39 $ 6.21 $ 5.86 $ 6.70 $ 6.77 $ 6.73 $ 7.38 $ 8.69 $11.79 $ 8.65
Royalties $ 1.73 $ 1.13 $ 1.12 $ 1.29 $ 1.31 $ 1.33 $ 1.50 $ 1.96 $ 2.34 $ 1.78
Production Expenses $ 0.79 $ 0.79 $ 0.83 $ 0.84 $ 0.81 $ 0.66 $ 0.68 $ 0.74 $ 0.74 $ 0.71
NETBACK $ 5.87 $ 4.29 $ 3.91 $ 4.57 $ 4.65 $ 4.74 $ 5.20 $ 5.99 $ 8.71 $ 6.16
NORTH SEA PRODUCT NETBACKS
Light Crude Oil ($/bbl)
Sales Price (1) $68.05 $73.19 $78.68 $67.72 $72.62 $59.56 $64.81 $74.46 $66.88 $66.57
Royalties $ 0.12 $ 0.17 $ 0.11 $ 0.14 $ 0.13 $ 0.05 $ 0.11 $ 0.12 $ 0.14 $ 0.10
Production Expenses $16.85 $17.18 $20.28 $14.76 $17.57 $14.91 $17.41 $15.15 $12.11 $14.94
NETBACK $51.08 $55.84 $58.29 $52.82 $54.92 $44.60 $47.29 $59.19 $54.63 $51.53
Natural Gas ($/mcf)
Sales Price (1) $ 2.38 $ 2.33 $ 2.38 $ 3.48 $ 2.66 $ 3.52 $ 3.07 $ 2.64 $ 3.40 $ 3.17
Royalties $ - $ - $ - $ - $ - $ - $ - $ - $ - $ -
Production Expenses $ 1.26 $ 1.47 $ 1.30 $ 1.54 $ 1.40 $ 2.52 $ 2.92 $ 2.30 $ 1.96 $ 2.44
NETBACK $ 1.12 $ 0.86 $ 1.08 $ 1.94 $ 1.26 $ 1.00 $ 0.15 $ 0.34 $ 1.44 $ 0.73
OFFSHORE WEST AFRICA PRODUCT NETBACKS
Light Crude Oil ($/bbl)
Sales Price (1) $65.23 $72.97 $70.59 $63.50 $67.99 $62.34 $58.24 $59.09 $60.19 $59.91
Royalties $ 1.55 $ 1.87 $ 4.89 $ 3.02 $ 2.81 $ 1.90 $ 1.81 $ 1.54 $ 1.57 $ 1.62
Production Expenses $ 6.08 $ 5.61 $ 7.97 $10.05 $ 7.45 $11.43 $ 8.47 $ 5.81 $ 5.62 $ 6.50
NETBACK $57.60 $65.49 $57.73 $50.43 $57.73 $49.01 $47.96 $51.74 $53.00 $51.79
Natural Gas ($/mcf)
Sales Price (1) $ 5.59 $ 5.30 $ 4.97 $ 5.72 $ 5.37 $ 7.67 $ 6.88 $ 5.52 $ 5.13 $ 5.91
Royalties $ 0.13 $ 0.14 $ 0.34 $ 0.27 $ 0.22 $ 0.23 $ 0.21 $ 0.13 $ 0.14 $ 0.16
Production Expenses $ 1.00 $ 0.36 $ 1.39 $ 2.01 $ 1.19 $ 1.25 $ 1.37 $ 1.09 $ 0.80 $ 1.05
NETBACK $ 4.46 $ 4.80 $ 3.24 $ 3.44 $ 3.96 $ 6.19 $ 5.30 $ 4.30 $ 4.19 $ 4.70
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) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES.
53
NETBACKS
INFORMATION BY QUARTER
YEAR 2004
--------------------------------------------------------------
1ST 2ND 3RD 4TH YEAR
QUARTER QUARTER QUARTER QUARTER ENDED
------- ------- ------- ------- -----
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS
Light/Pelican Lake/NGLs ($/bbl)
Sales Price (1) $37.54 $ 41.03 $ 44.89 $ 43.80 $ 41.81
Royalties $ 7.20 $ 7.91 $ 8.59 $ 8.76 $ 8.12
Production Expenses $ 7.30 $ 7.74 $ 7.75 $ 7.85 $ 7.66
NETBACK $23.04 $ 25.38 $ 28.55 $ 27.19 $ 26.03
Heavy Crude Oil ($/bbl)
Sales Price (1) $27.00 $ 28.08 $ 35.33 $ 25.16 $ 28.99
Royalties $ 2.02 $ 2.31 $ 3.18 $ 1.77 $ 2.34
Production Expenses $ 9.38 $ 9.47 $ 9.72 $ 9.62 $ 9.56
NETBACK $15.60 $ 16.30 $ 22.43 $ 13.77 $ 17.09
Natural Gas ($/mcf)
Sales Price (1) $ 6.37 $ 6.78 $ 6.36 $ 6.88 $ 6.61
Royalties $ 1.33 $ 1.44 $ 1.45 $ 1.39 $ 1.40
Production Expenses $ 0.60 $ 0.60 $ 0.63 $ 0.63 $ 0.62
NETBACK $ 4.44 $ 4.74 $ 4.28 $ 4.86 $ 4.59
NORTH SEA PRODUCT NETBACKS
Light Crude oil ($/bbl)
Sales Price (1) $44.27 $ 49.22 $ 57.39 $ 52.77 $ 51.37
Royalties $ 0.06 $ 0.10 $ 0.09 $ 0.08 $ 0.08
Production Expenses $13.26 $ 13.84 $ 13.88 $ 14.96 $ 14.03
NETBACK $30.95 $ 35.28 $ 43.42 $ 37.73 $ 37.26
Natural Gas ($/mcf)
Sales Price (1) $ 5.08 $ 3.28 $ 3.17 $ 3.26 $ 3.73
Royalties $ - $ - $ - $ - $ -
Production Expenses $ 1.65 $ 1.92 $ 2.48 $ 2.29 $ 2.07
NETBACK $ 3.43 $ 1.36 $ 0.69 $ 0.97 $ 1.66
OFFSHORE WEST AFRICA PRODUCT NETBACKS
Light Crude oil ($/bbl)
Sales Price (1) $42.08 $ 49.34 $ 53.86 $ 51.28 $ 49.05
Royalties $ 1.28 $ 1.52 $ 1.42 $ 1.52 $ 1.43
Production Expenses $ 7.09 $ 7.43 $ 8.05 $ 7.82 $ 7.59
NETBACK $33.71 $ 40.39 $ 44.39 $ 41.94 $ 40.03
Natural Gas ($/mcf)
Sales Price (1) $ 4.80 $ 5.18 $ 6.31 $ 4.73 $ 5.25
Royalties $ 0.15 $ 0.16 $ 0.17 $ 0.14 $ 0.15
Production Expenses $ 1.23 $ 1.38 $ 1.39 $ 1.31 $ 1.33
NETBACK $ 3.42 $ 3.64 $ 4.75 $ 3.28 $ 3.77
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) NET OF TRANSPORTATION AND BLENDING COSTS AND EXCLUDING RISK MANAGEMENT
ACTIVITIES..
F. HISTORICAL DRILLING ACTIVITY BY PRODUCT
The following table sets forth the gross and net wells (excluding service and
stratigraphic test wells) in which the Company has participated for the period
indicated:
YEAR ENDED DECEMBER 31
---------------------------------------------------------
2006 2005
Gross Net Gross Net
------------------------ ------------------------
Natural Gas 855 641 1,071 890
Crude Oil 666 603 685 627
Service/Stratigraphic 376 375 251 248
Dry Holes 133 119 136 117
------------------------ ------------------------
Total 2,030 1,738 2,143 1,882
======================== ========================
Total Success Rate 91% 93%
55
G. NET 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. Net capital expenditures do
not include non-cash property, plant and equipment additions and disposals.
YEAR ENDED DECEMBER 31
-------------------------------------
2006 2005
-------------------------------------
$millions
Net property acquisitions (dispositions) (1) 4,733 (320)
Land acquisition and retention 210 254
Seismic evaluations 130 132
Well drilling, completion and equipping 2,340 2,000
Pipeline and production facilities 1,314 1,295
---------------- ---------------
Reserve replacement expenditures 8,727 3,361
---------------- ---------------
Horizon Project:
Phase 1 construction costs (2) 2,768 1,249
Phase 2 and 3 costs 79 -
Capitalized interest, stock based 338 250
compensation and other (2)
---------------- ---------------
Total Horizon Project 3,185 1,499
---------------- ---------------
Midstream 12 4
Abandonments (3) 75 46
Head office 26 22
---------------- ---------------
Total Net Capital Expenditures 12,025 4,932
================ ===============
56
2006 THREE MONTHS ENDED
---------------------------------------------------------------------
($ millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Net property acquisitions (dispositions) (1) 12 7 (6) 4,720
Land acquisition and retention 99 54 29 28
Seismic evaluation 52 35 26 17
Well drilling, completion and equipping 936 418 524 462
Pipeline and production facilities 500 233 270 311
----- ----- ----- -----
Reserve replacement expenditures 1,599 747 843 5,538
Horizon Project:
Phase 1 construction costs (2) 616 680 727 745
Phase 2 and 3 costs 1 6 18 54
Capitalized interest, stock based
compensation and other (2) 69 96 39 134
----- ----- ----- -----
Total Horizon Project 686 782 784 933
Midstream 3 6 2 1
Abandonments (3) 15 17 24 19
Head office 6 6 8 6
----- ----- ----- -----
Total Net Capital Expenditures 2,309 1,558 1,661 6,497
===== ===== ===== =====
57
2005 THREE MONTHS ENDED
---------------------------------------------------------------------
($ millions)
CAPITAL EXPENDITURES
BY QUARTER MAR. 31 JUNE 30 SEPT. 30 DEC. 31
------- ------- -------- -------
Net property acquisitions (dispositions)(1)
2 (341) - 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 (2) 131 236 413 469
Phase 2 and 3 costs - - - -
Capitalized interest, stock based
compensation and other (2) 84 39 39 88
----- --- ----- -----
Total Horizon Project 215 275 452 557
Midstream 4 - (1) 1
Abandonments (3) 4 7 19 16
Head office 4 7 5 6
----- --- ----- -----
Total Net Capital Expenditures 1,372 609 1,272 1,679
===== === ===== =====
(1) Includes Business Combinations
(2) Certain prior period amounts have been reclassified with respect to
stock-based compensation costs.
(3) Abandonments represent expenditures to settle asset retirement obligations
and have been reflected as capital expenditures in this table.
58
H. UNDEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region undeveloped acreage as at December 31, 2006:
GROSS ACRES NET ACRES
----------- ---------
(thousands) (thousands)
NORTH AMERICA
Alberta 11,298 9,363
British Columbia 3,752 2,692
Saskatchewan 787 719
Manitoba 11 11
NORTH SEA
United Kingdom 367 299
OFFSHORE WEST AFRICA
Cote d'Ivoire 95 55
Gabon 152 152
-------------- -----------
Total 16,462 13,291
============== ===========
I. DEVELOPED ACREAGE
The following table summarizes the Company's working interest holdings in core
region developed acreage as at December 31, 2006:
GROSS ACRES NET ACRES
----------- ---------
(thousands) (thousands)
NORTH AMERICA
Alberta 6,398 5,078
British Columbia 1,319 996
Saskatchewan 340 287
Manitoba 5 5
NORTH SEA
United Kingdom 138 93
OFFSHORE WEST AFRICA
Cote d'Ivoire 7 4
-------------- -----------
Total 8,207 6,463
============== ===========
59
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
-----------------------------
2006 2005
---- ----
($ millions, except per share
information)
Revenues (1) (net of royalties) 10,398 9,764
Cash flow from operations 4,932 5,021
Per common share - basic 9.18 9.36
- diluted 9.18 9.33
Net earnings 2,524 1,050
Per common share - basic 4.70 1.96
- diluted 4.70 1.95
Total assets 33,160 21,852
Total long-term debt 11,043 3,321
---------------------------------------------------------------------
2006 THREE MONTHS ENDED
---------------------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (1) (net of royalties) 2,352 2,739 2,798 2,509
Net earnings 57 1,038 1,116 313
Per common share - basic 0.11 1.93 2.08 0.58
- diluted 0.11 1.93 2.08 0.58
---------------------------------------------------------------------
2005 THREE MONTHS ENDED
---------------------------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
($ millions, except per share information)
Revenues (1) (net of royalties) 1,969 2,137 2,760 2,898
Net (loss) earnings (424) 219 151 1,104
Per common share - basic (0.79) 0.41 0.28 2.06
- diluted (0.79) 0.41 0.28 2.06
(1) Blending costs previously netted against gross revenues in prior years
have been reclassified to transportation and blending expense to conform
to the presentation adopted in 2006..
60
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.
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 is rated "Baa2" with a stable outlook by Moody's Investors Service,
Inc. ("Moody's"), "BBB" by Standard & Poor's Corporation ("S&P") with a stable
outlook and "BBB high" with a negative trend by DBRS.
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
Baa 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.
61
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 debt securities. 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 rating trend is DBRS' opinion regarding the outlook for the
rating.
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.
2006 Monthly Historical Trading on Toronto Stock Exchange
Month High Low Close Volume Traded
January $71.65 $57.75 $70.60 40,613,480
February 73.91 58.96 62.09 50,126,147
March 68.93 61.75 64.90 43,747,239
April 72.70 65.58 67.20 28,568,500
May 69.37 54.39 58.00 52,879,861
June 62.75 50.78 61.72 47,587,703
July 62.60 54.59 60.10 31,911,426
August 63.30 56.89 58.03 38,653,456
September 58.59 47.28 50.94 56,457,171
October 60.73 45.49 58.45 50,270,814
November 62.50 54.21 61.90 42,470,275
December 63.50 58.64 62.15 25,649,324
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
62
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
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. Under this
program, the Company purchased a total of 485,000 common shares for
cancellation at a weighted average purchase price of $57.29 for each common
share purchased, $57.33 after costs.
On January 22, 2007, the Company announced its intention to make a Normal
Course Issuer Bid through the facilities of TSE and the NYSE, commencing
January 24, 2007 and ending January 23, 2008, to purchase for cancellation up
to 26,941,730 common shares of the Company, being 5 per cent of the 538,834,606
common shares of the Company outstanding on January 15, 2007. As of the date of
this Annual Information Form, no shares have been purchased under the program.
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.
2006 2005 2004
---- ---- ----
Cash dividends declared per common share $0.30 $0.24 $0.20
63
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.
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 53) Financial Officer of the Calgary Health Region from 2002 to
Canada present; Vice-President, Corporate Services and Chief
Financial Officer of the Calgary Health Region from
February 2000 to 2002; prior thereto with Ernst & Young
since 1980, most recently as a Corporate Audit Partner from
1991 to 2000. Has served continuously as a director of the
Company since November 2003. Currently serving on the board
of directors of Enbridge Income Fund.
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 47) 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 based
Winnipeg, Manitoba (age 64) in Winnipeg, Manitoba). Prior thereto, served as Premier
Canada 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 MTS Allstream Inc.,
Pollard Banknote Income Fund, Arctic Glacier Income Trust,
Exchange Industrial Income Fund, Wellington West Capital
Inc. and FWS Construction Inc.
Ambassador Gordon D. Giffin Director(1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm)
Atlanta, Georgia (age 57) 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, Ontario Energy Savings Corp. 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 61)
Steve W. Laut President and Chief President and Chief Operating Officer of the Company since
Calgary, Alberta Operating Officer and April 2005. Prior thereto Executive Vice-President,
Canada Director Operations 2001 to 2003 and most recently Chief Operating
(age 49) Officer 2003 to 2005. Has served continuously as a
director of the Company since August 2006.
64
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
Keith A.J. MacPhail Director(3)(5) Chairman, President and Chief Executive Officer, Bonavista
Calgary, Alberta (age 50) Petroleum Ltd. since November 1997 and Chairman, President
Canada and Chief Executive Officer of Bonavista Energy Trust 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 61) director of the Company since January 1989.
Canada
Norman F. McIntyre Director(3)(4)(5) An independent businessman. Prior thereto Executive
Calgary, Alberta (age 61) 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.
Frank J. McKenna Director(1)(4) Deputy Chair, TD Bank Financial Group. Prior thereto
Cap Pele, New Brunswick (age 59) Premier of New Brunswick from 1987 to 1997; Counsel to
Canada Atlantic Canada law firm McInnes Cooper from 1998 to 2005,
and most recently Canadian Ambassador to the United States
from 2005 to 2006. He has served continuously as a director
of the Company since August 2006. Currently serving on the
board of directors of Brookfield Asset Management Inc.;
and, Perseus Private Equity a private equity fund
management company.
James S. Palmer, C.M., A. O. Director(3)(4)(5) Chairman and a Partner of Burnet, Duckworth & Palmer LLP
E., Q.C. (age 78) (law firm). Has served continuously as a director of the
Calgary, Alberta Company since May 1997.
Canada Currently serving on the board of directors of Magellan
Aerospace Corporation; Rally Energy Corp.; and, Energy
Resources Alberta.
Dr. Eldon R. Smith, OC, M.D. Director(4)(5) Emeritus Professor and Former Dean, Faculty of Medicine,
Calgary, Alberta (age 67) 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., Sernova Corp.;
and, Overlord Financial Inc.
David A. Tuer Director(1)(2)(3) Chairman, Calgary Health Region since October 2001 and
Calgary, Alberta (age 57) Executive Vice-Chairman BA Energy Inc. since April 2005.
Canada Prior thereto President and Chief Executive Officer,
PanCanadian Energy Corporation from December 1994 to
October 2001, President and CEO of Hawker Resources Inc.
(independent oil and natural gas company) from January
2003 to March 2005 and most recently President, Value
Creation Inc. from April 2005 to February 2006. Has served
continuously as a director of the Company since May 2002.
Currently serving on the board of directors of BA Energy
Inc; Rockwater Capital Corporation; Daylight Resources
Trust; Xtreme Coil Drilling Corp. and, Altalink Management
Ltd. a private company.
Real M. Cusson Senior Vice-President, Officer of the Company.
Calgary, Alberta Marketing
Canada (age 56)
Real J. H. Doucet Senior Vice-President, Officer of the Company.
Calgary, Alberta Oil Sands
Canada (age 54)
65
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
Allen M. Knight Senior Vice-President, Officer of the Company.
Calgary, Alberta International &
Canada Corporate Development
(age 57)
Tim S. McKay Senior Vice-President, Officer of the Company.
Calgary, Alberta Operations
Canada (age 45)
Douglas A. Proll Chief Financial Officer Officer of the Company.
Calgary, Alberta and Senior
Canada Vice-President, Finance
(age 56)
Lyle G. Stevens Senior Vice-President, Officer of the Company.
Calgary, Alberta Exploitation
Canada (age 52)
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 54)
Corey B. Bieber Vice-President, Finance Officer of the Company since April 2005; prior thereto
Calgary, Alberta and Investor Relations Treasurer of the Company March 2001 to July 2002; Director,
Canada (age 43) Investor Relations of the Company from July 2002 to April
2005 and most recently Vice-President, Investor Relations
April 2005 to February 2007.
Mary-Jo Case Vice-President, Land Officer of the Company since May 2002; prior thereto
Calgary, Alberta (age 48) Co-ordinator Land at PanCanadian Petroleum Limited to 1999
Canada and most recently Manager Commercial Ventures and Land at
PanCanadian Petroleum Limited 1999 to 2002.
William R. Clapperton Vice-President, Officer of the Company since January 2002.
Calgary, Alberta Regulatory, Stakeholder
Canada and Environmental Affairs
(age 44)
James F. Corson Vice-President, Human Officer of the Company since January 2007; prior thereto
Calgary, Alberta Resources, Horizon Vice-President, Human Resources of Qatar Petroleum Corp.
Canada (age 56) from March 1997 to July 2005 and most recently Director
Human Resources and Stakeholder Relations of the Company
from July 2005 to 2007.
Gordon M. Coveney Vice-President, Officer of the Company since September 2003; prior thereto
Calgary, Alberta Exploration, East Exploration Manager for the Company.
Canada (age 53)
Randall S. Davis Vice-President, Finance Officer of the Company since July 2004; prior thereto
Calgary, Alberta and Accounting Manager, Financial Reporting of the Company to July 2002;
Canada (age 40) Financial Controller of the Company from July 2002 to July
2004 and most recently Vice-President Financial Accouting
and Controls July 2004 to February 2007.
Allan Frankiw Vice-President, Officer of the Company since March 2007; prior thereto
Calgary, Alberta Production, Central Manager Midstream for Anadarko Canada Corporation from
Canada (age 50) November 1998 to March 2005, Manager Facilities &
Construction for Anadarko Canada Corporation from April
2005 to November 2006, and most recently Manager Production
of the Company from November 2006 to March 2007.
66
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
Larry C. Galea Vice-President, Officer of the Company since April 2005; prior thereto
Calgary, Alberta Exploitation, Central Exploitation Manager of the Company to January 2002,
Canada (age 41) Manager, Operations Planning of the Company January 2002
to April 2004, and most recently Exploitation Manager of
the Company 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 53)
Peter Janson Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Engineering Integration Director, Production Planning and Control at Suncor Oil
Canada (age 49) Sands to June 2000 and 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 West Exploitation Manager of the Company to April 2004.
Canada (age 39)
Christopher M. Kean Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Utilities and Offsite, Manager Facilities Engineering of the Company to January
Canada Horizon Oil Sands Project 2002 , Utilities and Offsites Project Manager of the
(age 43) Company January 2002 to July 2002, Director, Utilities and
Offsites of the Company July 2002 to July 2003 and most
recently General Manager, Utilities and Offsites of the
Company July 2003 to December 2004.
Philip A. Keele Vice-President, Mining, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Horizon Oil Sands Project Mine Manager at Fording Coal Limited to February 2001,
Canada (age 47) 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 Development Operations Production Engineer of the Company to March 2000, Manager,
Canada (age 39) Field Operations of the Company from April 2000 to
September 2002, Vice-President, Field Operations of the
Company September 2002 until November 2006 and most
recently Vice-President Production Central of the Company
November 2006 to March 2007.
Richard P. Lock Vice-President, Bitumen Officer of the Company since July 2006; prior thereto
Calgary, Alberta Production Senior Manager Production of Diavik Diamond Mines Inc. June
Canada (age 41) 2002 to October 2003 and Vice-President Development October
2003 to June 2004 of Diavik Diamond Mines Inc., Project
Manager Extraction of the Company June 2004 to July 2005
and most recently General Manager, Bitumen Production of
the Company July 2005 to July 2006.
Leon Miura Vice-President, Upgrading Officer of the Company since August 2003; prior thereto
Calgary, Alberta (age 52) 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 45) Manager, Production Engineering of the Company from July
2001 to June 2002 and most recently Production Manager,
Heavy Oil of the Company from July 2002 to April 2004.
67
POSITION PRINCIPAL
PRESENTLY OCCUPATION
NAME HELD DURING PAST 5 YEARS
David A. Payne Vice-President, Officer of the Company since October 2004; prior thereto
Calgary, Alberta Exploitation, East Exploitation Manager, Thermal Heavy of the Company to July
Canada (age 45) 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 40)
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 60) 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.
Timothy G. Reed Vice-President, Human Officer of the Company since January 2007; prior thereto
Calgary, Alberta Resources Manager, Human Resources of the Company 2000 to 2005 and
Canada (age 50) most recently Director, Human Resources 2005 to January
2007.
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 39) 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 45) 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.
Scott G. Stauth Vice-President, Field Officer of the Company since November 2006; prior thereto
Calgary, Alberta Operations Operations Superintendent of the Company April 1997 to
Canada (age 49) April 2003 and most recently Manager, Eastern Field
Operations of the Company April 2003 to November 2006.
Stephen C. Suche Vice-President, Officer of the Company since July 2006; prior thereto
Calgary, Alberta Information and Manager Information and Corporate Services of the Company
Canada Corporate Services January 2000 to July 2006.
(age 47)
Domenic Torriero Vice-President, Officer of the Company since November 2006; prior thereto
Calgary, Alberta Exploration Vice-President Geology and Geophysics of Petrovera
Canada (age 42) Resources Limited January 1999 to March 2004 and most
recently Exploration Manager of the Company March 2004 to
November 2006.
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 Limited
Canada (age 50) 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.
Bruce E. McGrath Corporate Secretary Officer of the Company.
Calgary, Alberta (age 57)
Canada
68
(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 Health, Safety, and Environmental Committee
All directors stand for election at each Annual General Meeting of Canadian
Natural shareholders. With the exception of Messrs. S. W. Laut and F. J.
McKenna who were appointed to the Board effective August 1, 2006, all of the
current directors were elected to the Board at the last annual meeting of
shareholders held on May 4, 2006. All of the current directors are standing for
election at the Annual Special Meeting of Shareholders scheduled for May 3,
2007.
As at December 31, 2006, 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.
69
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
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 2006 approved specified audit and non-audit services to
be performed by PricewaterhouseCoopers LLP ("PwC") the independent auditor of
the Corporation.
AUDITOR SERVICE FEES
The Audit Committee of the Board of Directors in 2006 approved specified audit
and non-audit services to be performed by PwC. The services provided include:
(i) the annual audit of the Corporation's internal controls and December 31,
2006 consolidated financial statements included in the Annual Information Form
and Form 40-F, reviews of the Corporation's unaudited first, second, and third
70
quarter interim Consolidated Financial Statements, audits of certain of the
Corporation's subsidiary companies' annual financial statements as well as
other audit services provided in connection with statutory and regulatory
filings; (ii) audit related services related to debt covenant compliance, Crown
Royalty Statements; (iii) tax related services related to expatriate personal
tax and compliance as well as other corporate tax return matters; and (iv)
non-audit services related to accessing resource materials through PwC's
accounting literature library.
Fiscal 2006 fees accrued to PwC will not exceed those amounts shown in the
table below.
AUDITOR SERVICE 2006 2005
--------------- ---- ----
Audit fees $3,126,287 $1,227,835
Audit related fees $121,353 $266,923
Tax related fees $134,025 $39,331
All other fees $9,516 $7,290
-------------------------------------------------------
$3,391,181 $1,541,379
-------------------------------------------------------
The Charter of the Audit Committee of the Company is attached as Schedule "C"
to this Annual Information Form.
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,
2006. PricewaterhouseCoopers LLP is independent in accordance with the Rules of
Professional Conduct as outlined by the Institute of Chartered Accountants of
Alberta.
Based on information provided by the relevant persons or companies, there are
beneficial interests, direct or indirect, in less than 1% of the Company's
securities or property or securities or property of our associates or
affiliates held by Sproule Associates Limited, Ryder Scott Company or GLJ
Petroleum Consultants Ltd. or any partners, employees or consultants of such
independent reserves evaluators who participated in and who were in a position
to directly influence the preparation of the relevant report, or any such
71
person who, at the time of the preparation of the report was in a position to
directly influence the outcome of the preparation of the report.
ADDITIONAL INFORMATION
Additional information relating to the Company can be found on the SEDAR
website at www.sedar.com
Additional information including Directors' and Executive Officers'
remuneration and indebtedness, principal holders of the Company's securities,
options to purchase the Company's securities and interest of insiders in
material transactions is contained in the Company's Notice of Annual and
Special Meeting and Information Circular dated March 14, 2007 in connection
with the Annual and Special Meeting of Shareholders of Canadian Natural to be
held on May 3, 2007 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, 2006 found on pages 42 to 71,
72 to 98 and 99 to 103 respectively, of the 2006 Annual Report to the
Shareholders, which information is incorporated herein by reference.
For additional copies of this Annual Information Form, please contact:
Corporate Secretary of the Corporation at:
2500, 855 - 2nd Street S.W.
Calgary, Alberta T2P 4J8
72
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,
2006. 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,
2006 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, 2006 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, 2006.
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 "COGEH") 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
73
using a discount rate of 10 percent, included in the reserves data of
the Corporation evaluated by us for the year ended December 31, 2006
except as noted in 1(c)(i), 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 NET PRESENT VALUES OF CONVENTIONAL RESERVES
QUALIFIED PREPARATION (COUNTRY OR FOREIGN
RESERVES DATE OF GEOGRAPHIC AREA) (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
EVALUATOR OR EVALUATION ----------------------------------------------------
AUDITOR REPORT AUDITED EVALUATED REVIEWED TOTAL
MM$ MM$ MM$ MM$
------------------------------------------------------------------------------------------------------------
Sproule Sproule Canada, USA $0 $20,260 $0 $20,260
Associates Ltd. Evaluated the
P&NG
Reserves as
reported
February 5th,
2007.
------------------------------------------------------------------------------------------------------------
Ryder Scott Ryder Scott United Kingdom and $0 $7,237 $0 $7,237
Company Evaluated the Offshore West Africa
P&NG Reserves
as reported
February 5th,
2007.
------------------------------------------------------------------------------------------------------------
TOTALS $0 $27,497 $0 $27,497
============================================================================================================
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, 2006. GLJ
Petroleum Consultants Ltd. ("GLJ"), an independent qualified reserves
evaluator, was retained by the Reserves Committee of Canadian
Natural's Board of Directors to evaluate reserves associated with the
Horizon Project incorporating both the mining and upgrading projects.
These reserves were evaluated under SEC Industry Guide 7 and are
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.
74
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 5th, 2007
SPROULE ASSOCIATES LIMITED
ORIGINAL SIGNED BY:
Harry J. Helwerda, P.Eng.,
Senior Vice-President, Engineering,
ORIGINAL SIGNED BY:
Doug Ho, P.Eng.
Vice-President, Engineering, and Director
ORIGINAL SIGNED BY:
Ken H. Crowther, P.Eng.
President, Canada and U.S.
RYDER SCOTT COMPANY
ORIGINAL SIGNED BY:
Jane Tink, P.Eng.,
Senior Vice-President, Engineering
GLJ PETROLEUM CONSULTANTS LTD.
ORIGINAL SIGNED BY:
James H. Willmon, P.Eng.
Vice-President, Corporate Evaluations
75
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, 2006 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; and,
(b) (i) both proved, and proved and probable conventional crude oil,
NGLs and natural gas reserve quantities estimated as at
December 31, 2006 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, 2006.
Sproule Associates Limited, Ryder Scott Company and GLJ Petroleum Consultants
Ltd., all independent qualified reserves evaluators have evaluated the
Corporation's reserves data. The report of the independent qualified reserves
evaluators 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 evaluators;
(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.
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:
76
(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.
"Signed"
Steve W. Laut
President and Chief Operating Officer
"Signed"
Douglas A. Proll
Chief Financial Officer and Senior Vice President, Finance
"Signed"
David A. Tuer
Independent Director and Chair of the Reserve Committee
"Signed"
Norman F. McIntyre
Independent Director and Member of the Reserve Committee
Dated this 3rd day of March, 2007
Calgary, Alberta
77
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 management expertise and qualify as a
78
"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;
79
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 to the Board of Directors
for appointment by the shareholders, the
Corporation's independent auditors, review the
independence and monitor the 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 pre-approve all 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:
80
(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;
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; and
h. to review and approve the Corporation's hiring
policies regarding partners, employees and former
partners and employees of the present and former
independent auditor of the Corporation.
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;
81
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,
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, the earnings press
releases before disclosure to the public 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, the earnings press
releases before disclosure to the public and report
to the Board with respect thereto;
c. to ensure adequate procedures are in place for the
review of the Corporation's public disclosure of
financial information extracted or derived from the
Corporation's financial statements, other than the
quarterly and annual earnings press releases, and
periodically assess the adequacy of those
procedures;
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 establish procedures for:
(i) the receipt, retention and treatment of
complaints received by the Corporation
regarding accounting, internal accounting
controls, or auditing matters; and
(ii) the confidential, anonymous submission by
employees of the Corporation of concerns
regarding questionable accounting or auditing
matters;
g. to co-ordinate meetings with the Reserves Committee
of the Corporation, the Corporation's senior
engineering management, independent evaluating
82
engineers and auditors as required and consider such
further inquiries as are necessary to approve the
consolidated financial statements;
h. 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;
i. 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,
j. 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 Corporation's independent auditors in connection with
the issuance of its audit report, or to any consultants or experts employed by
the Audit Committee.
Consolidated Balance Sheets
As at December 31
(millions of Canadian dollars) 2006 2005
--------------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 23 $ 18
Accounts receivable and other 1,947 1,546
Future income tax (note 8) 163 487
Current portion of other
long-term assets (note 3) 106 -
--------------------------------------------------------------------------------
2,239 2,051
Property, plant and equipment (note 4) 30,767 19,694
Other long-term assets (note 3) 154 107
--------------------------------------------------------------------------------
$ 33,160 $21,852
--------------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 842 $ 573
Accrued liabilities 1,618 1,781
Current portion of other long-term
liabilities (note 6) 611 1,471
--------------------------------------------------------------------------------
3,071 3,825
Long-term debt (note 5) 11,043 3,321
Other long-term liabilities (note 6) 1,393 1,434
Future income tax (note 8) 6,963 5,035
--------------------------------------------------------------------------------
22,470 13,615
--------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital (note 9) 2,562 2,442
Retained earnings 8,141 5,804
Foreign currency translation
adjustment (note 10) (13) (9)
--------------------------------------------------------------------------------
10,690 8,237
--------------------------------------------------------------------------------
$ 33,160 $21,852
--------------------------------------------------------------------------------
Commitments and contingencies (note 13)
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 Statements of Earnings
For the years ended December 31
(millions of Canadian dollars,
except per common share amounts) 2006 2005 2004
--------------------------------------------------------------------------------
Revenue $ 11,643 $ 11,130 $ 8,269
Less: royalties (1,245) (1,366) (1,011)
--------------------------------------------------------------------------------
Revenue, net of royalties 10,398 9,764 7,258
--------------------------------------------------------------------------------
Expenses
Production 1,949 1,663 1,400
Transportation and blending 1,443 1,293 972
Depletion, depreciation and amortization 2,391 2,013 1,769
Asset retirement obligation accretion (note 6) 68 69 51
Administration 180 151 125
Stock-based compensation (note 6) 139 723 249
Interest, net 140 149 189
Risk management activities (note 12) 312 1,952 434
Foreign exchange loss (gain) 122 (132) (91)
--------------------------------------------------------------------------------
6,744 7,881 5,098
--------------------------------------------------------------------------------
Earnings before taxes 3,654 1,883 2,160
Taxes other than income tax (note 8) 256 194 165
Current income tax (note 8) 222 286 116
Future income tax (note 8) 652 353 474
--------------------------------------------------------------------------------
Net earnings $ 2,524 $ 1,050 $ 1,405
--------------------------------------------------------------------------------
Net earnings per common share (note 11)
Basic $ 4.70 $ 1.96 $ 2.62
Diluted $ 4.70 $ 1.95 $ 2.60
--------------------------------------------------------------------------------
Consolidated Statements of Retained Earnings
For the years ended December 31
(millions of Canadian dollars) 2006 2005 2004
--------------------------------------------------------------------------------
Balance - beginning of year $ 5,804 $ 4,922 $ 3,650
Net earnings 2,524 1,050 1,405
Dividends on common shares (note 9) (161) (127) (107)
Purchase of common shares under Normal
Course Issuer Bid (note 9) (26) (41) (26)
--------------------------------------------------------------------------------
Balance - end of year $ 8,141 $ 5,804 $ 4,922
--------------------------------------------------------------------------------
Consolidated Statements of Cash Flows
For the years ended December 31 (
millions of Canadian dollars) 2006 2005 2004
--------------------------------------------------------------------------------
Operating activities
Net earnings $ 2,524 $ 1,050 $ 1,405
Non-cash items
Depletion, depreciation and amortization 2,391 2,013 1,769
Asset retirement obligation accretion 68 69 51
Stock-based compensation 139 723 249
Unrealized risk management activities (1,013) 925 (40)
Unrealized foreign exchange loss (gain) 134 (103) (94)
Deferred petroleum revenue tax expense
(recovery) 37 (9) (45)
Future income tax 652 353 474
Deferred charges (2) (31) (33)
Abandonment expenditures (75) (46) (32)
Net change in non-cash working capital
(note 14) (679) (147) (14)
--------------------------------------------------------------------------------
4,176 4,797 3,690
--------------------------------------------------------------------------------
Financing activities
Issue(repayment)of bank credit facilities 6,499 (435) 357
Issue (repayment) of medium-term notes 400 400 (125)
Repayment of senior unsecured notes - (194) (54)
Issue of US dollar debt securities 788 - 830
Repayment of preferred securities - (107) -
Repayment of obligations under capital leases - - (7)
Issue of common shares on exercise of
stock options 21 9 24
Dividends on common shares (153) (121) (101)
Purchase of common shares (28) (45) (33)
Net change in non-cash working capital (note 14) 37 19 6
--------------------------------------------------------------------------------
7,564 (474) 897
--------------------------------------------------------------------------------
Investing activities
Expenditures on property, plant and
equipment (7,266) (5,340) (4,582)
Net proceeds on sale of property, plant and
equipment 71 454 7
--------------------------------------------------------------------------------
Net expenditures on property, plant and
equipment (7,195) (4,886) (4,575)
Acquisition of Anadarko Canada Corporation
(note 2) (4,641) - -
Net proceeds on sale of other assets - 11 -
Net change in non-cash working capital
(note 14) 101 542 (88)
--------------------------------------------------------------------------------
(11,735) (4,333) (4,663)
--------------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 5 (10) (76)
Cash and cash equivalents - beginning of year 18 28 104
--------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 23 $ 18 $ 28
--------------------------------------------------------------------------------
Supplemental disclosure of cash flow information (note 14)
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 produce
synthetic crude oil through mining and upgrading 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
16.
Signficant accounting policies are summarized as follows:
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and
all of its subsidiary companies 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.
Purchase price allocations, 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 infiation 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 in the United Kingdom 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 at
purchase 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 its conventional
crude oil and natural gas properties and equipment as prescribed by Accounting
Guideline 16 ("AcG 16") 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 are accounted for
as capital leases or operating leases as appropriate.
Property acquisition, construction and development costs related to the
Company's Horizon Project are not accounted for under the full cost method of
accounting and accordingly, are excluded from the Company's Canadian
conventional oil and gas cost centre. Construction costs are capitalized
separately to each phase of the Horizon Project. The Company will review the
recoverability of the carrying amount of the Horizon Project costs if events or
circumstances indicate that the carrying amount may not be recoverable.
(E) DEPLETION, DEPRECIATION AND AMORTIZATION
Substantially all costs related to each country-by-country 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. Costs for major development projects, as identified by
management, 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
Following the Board of Directors' approval of Phase 1 of the Horizon Project in
2005, the Company commenced capitalization of construction period interest based
on costs incurred and the Company's cost of borrowing. Interest capitalization
on Phase 1 will cease once construction is substantially complete and this phase
of the Horizon Project is available for its intended use. The Company will
continue to capitalize a portion of interest costs related to subsequent phases
of the Horizon Project.
(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. Refer to policy note (R) for the effect of new financial instrument
policies on deferred charges.
(H) ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset retirement obligations on its resource
properties, facilities, production platforms and gathering systems 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 lives of the respective
assets. 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.
The Company's pipelines have an indeterminate 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 year in
which the lives of the assets are determinable.
(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
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 assets.
Gains or losses on translation of integrated foreign operations are included in
the consolidated statement of earnings. Gains or losses on the translation of
foreign currency balances are either recognized in net earnings immediately, or
in the foreign currency translation adjustment (note 10) for translation gains
or losses for that portion of the US dollar denominated debt designated as a
hedge of the net investment in 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, delivery has taken place and collection is
reasonably assured. 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 AND BLENDING
Transportation and blending 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 CONTRACTS
Production generated from Offshore West Africa is currently shared under the
terms of various Production Sharing Contracts ("PSCs"). 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 then 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 as of 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.
Taxable income from the conventional crude oil and natural gas business in
Canada is primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
(O) STOCK-BASED COMPENSATION PLANS
The Company accounts for stock-based compensation using the intrinsic value
method as 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 and an estimated
forfeiture rate. This liability is revalued at each reporting date to reflect
changes in the market price of the Company's common shares and actual
forfeitures, with the net change recognized in net earnings, or adjusted to
capitalized costs 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.
(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 intended for trading or speculative purposes.
Changes in fair value of derivative financial instruments formally 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 formally 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 derivative financial instruments designated
as 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. All realized and unrealized gains or losses on these
contracts are included in risk management activities, regardless of whether or
not these contracts have been formally designated as hedges.
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 formally designated as hedges are included in interest
expense. Gains or losses on non-designated interest rate contracts are included
in risk management activities.
The Company enters into cross-currency swap agreements 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 the foreign exchange component of all cross-currency swap contracts
are included in risk management activities. Gains or losses on the interest
component of 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 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.
Risk management activities are included in operating activities in the
consolidated statements of cash flows.
Refer to policy note (R) for the effect of new accounting standards related to
the accounting for risk management activities.
(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 accounted for as a
liability are used to purchase common shares at the average market price during
the year. The Company's Option Plan described in note 9 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. The dilutive effect of other 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
Effective January 1, 2007, the Company will adopt the following new accounting
standards issued by the CICA relating to the accounting for and disclosure of
financial instruments:
o Section 1530 - "Comprehensive Income" introduces the concept of
comprehensive income to Canadian GAAP. 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.
Foreign currency translation adjustment, which is currently a separate
component of shareholders' equity, will be recorded as part of accumulated
other comprehensive income.
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 will be restated
only for the foreign currency translation adjustment.
o Section 3855 - "Financial Instruments - Recognition and Measurement"
prescribes when a financial asset, financial liability, or nonfinancial
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.
The Company will include all transaction costs that are directly
attributable to the acquisition or issue of a financial asset or financial
liability with the fair value of the financial asset or financial
liability. These adjustments were previously recorded in deferred charges.
Transaction costs included with the fair value of the financial asset or
financial liability will be amortized using the effective interest method.
o Section 3865 - "Hedges" replaces Accounting Guideline 13 - "Hedging
Relationships" and EIC 128 - "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments" and specifies how hedge
accounting is to be applied and what disclosures are necessary when hedge
accounting is applied.
Adoption of this standard will require the Company to record all of its
derivative financial instruments on the balance sheet at fair value,
including those designated as hedges. Designated hedges are currently not
recognized on the balance sheet but are disclosed in the notes to the
financial statements. The adjustment to recognize the designated hedges on
the balance sheet will be recorded as an adjustment to the opening balance
of retained earnings or accumulated other comprehensive income, as
appropriate.
Subsequently, 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 comprehensive income
each period and are recognized in the consolidated statements of earnings
when the hedged item is recognized. 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.
Adoption of these standards will have the following estimated effects on the
Company's consolidated balance sheet as at January 1, 2007:
Decrease future income tax asset $ (62)
Increase current portion of other long-term assets $ 193
Decrease other long-term assets $ (16)
Decrease long-term debt $ (72)
Increase future income tax liability $ 18
Increase retained earnings $ 10
Increase foreign currency translation adjustment $ 13
Increase accumulated other comprehensive income $ 146
--------------------------------------------------------------------------------
(S) COMPARATIVE FIGURES
Certain figures related to the presentation of gross revenues and gross
transportation and blending provided for prior years have been reclassified to
conform to the presentation adopted in 2006.
Common share data has been restated to reflect the two-for-one share split in
May 2005.
2. BUSINESS COMBINATIONS
ANADARKO CANADA CORPORATION
In November 2006, the Company completed the acquisition of all of the issued and
outstanding common shares of Anadarko Canada Corporation ("ACC"), a subsidiary
of Anadarko Petroleum Corporation, for net cash consideration of $4,641 million
including working capital and other adjustments. Substantially all of ACC's land
and production base are located in Western Canada.
The acquisition was accounted for using the purchase method. Operating results
from ACC have been consolidated with the results of the Company effective from
November 2, 2006, the date of acquisition, and are reported in the North America
segment. The preliminary allocation of the net purchase price is subject to
change as actual amounts are determined. The preliminary allocation of the net
purchase price to assets acquired and liabilities assumed based on their fair
values was as follows:
Net purchase price:
Net cash consideration (1) $ 4,641
--------------------------------------------------------------------------------
Net purchase price allocated as follows:
Non-cash working capital deficit assumed
and other $ (105)
Property, plant and equipment 6,249
Long-term debt (9)
Asset retirement obligation (56)
Future income tax (1,438)
--------------------------------------------------------------------------------
$ 4,641
================================================================================
(1) Net cash consideration was reduced by $88 million to reflect the settlement
of US dollar currency forward contracts designated as hedges of the ACC
share purchase price.
3. OTHER LONG-TERM ASSETS
2006 2005
--------------------------------------------------------------------------------
Deferred charges $ 109 $ 107
Risk management(note 12) 128 -
Other 23 -
--------------------------------------------------------------------------------
260 107
Less: current portion 106 -
--------------------------------------------------------------------------------
$ 154 $ 107
================================================================================
4. PROPERTY, PLANT AND EQUIPMENT
2006 2005
Accumulated Accumulated
depletion depletion
and and
Cost depreciation Net Cost depreciation Net
----------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 31,715 $ 9,836 $ 21,879 $ 22,258 $ 7,948 $ 14,310
North Sea 3,370 1,341 2,029 2,703 1,022 1,681
Offshore West Africa 1,685 481 1,204 1,547 294 1,253
Other 38 14 24 27 14 13
Horizon Project 5,350 - 5,350 2,169 - 2,169
Midstream 263 56 207 251 48 203
Head office 150 76 74 124 59 65
----------------------------------------------------------------------------------------------------
$ 42,571 $ 11,804 $ 30,767 $ 29,079 $ 9,385 $ 19,694
====================================================================================================
During the year ended December 31, 2006, the Company capitalized administrative
overhead of $41 million (2005 - $41 million, 2004 - $49 million) relating to
exploration and development in the North Sea and Offshore West Africa and $456
million (2005 - $236 million, 2004 - $35 million) relating primarily to the
Horizon Project in North America.
During the year ended December 31, 2006, the Company capitalized $196 million
(2005 -$72 million, 2004 -$nil) in construction period interest costs related to
the Horizon Project.
Included in property, plant and equipment are unproved land and major
development projects that are not currently subject to depletion or
depreciation:
2006 2005
--------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 2,244 $ 1,372
North Sea 24 28
Offshore West Africa 84 182
Other 24 13
Horizon Project 5,350 2,169
--------------------------------------------------------------------------------
$ 7,726 $ 3,764
================================================================================
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, 2006:
Average
annual
increase
2007 2008 2009 2010 2011 thereafter
----------------------------------------------------------------------------------------------------
Crude oil and NGLs
North America
WTI at Cushing (US$/bbl) $ 65.73 $ 68.82 $ 62.42 $ 58.37 $ 55.20 2.0%
Hardisty Heavy 12(degree)
API(C$/bbl) $ 42.98 $ 45.02 $ 40.74 $ 38.03 $ 35.90 2.0%
Edmonton Par (C$/bbl) $ 74.10 $ 77.62 $ 70.25 $ 65.56 $ 61.90 2.0%
North Sea and Offshore
West Africa
North Sea Brent (US$/bbl) $ 63.73 $ 66.78 $ 60.34 $ 56.24 $ 53.04 2.0%
----------------------------------------------------------------------------------------------------
Natural gas
North America
Henry Hub Louisiana
(US$/mmbtu) $ 7.85 $ 8.39 $ 7.65 $ 7.48 $ 7.63 2.0%
AECO (C$/mmbtu) $ 7.72 $ 8.59 $ 7.74 $ 7.55 $ 7.72 2.0%
Huntingdon/Sumas (C$/mmbtu) $ 7.48 $ 8.45 $ 7.60 $ 7.41 $ 7.58 2.0%
----------------------------------------------------------------------------------------------------
5. LONG-TERM DEBT
2006 2005
----------------------------------------------------------------------------------------------------------------------
Bank credit facilities
Bankers' acceptances $ 6,621 $ 122
Medium-term notes
7.40% unsecured debentures due March 1, 2007 125 125
4.50% unsecured debentures due January 23, 2013 400 -
4.95% unsecured debentures due June 1, 2015 400 400
Senior unsecured notes
Adjustable rate due May 27, 2009 (2006 - US$93 million, 2005 - US$93 million) 108 108
US dollar debt securities
7.80% due July 2, 2008 (2006 - US$8 million, 2005 - US$nil) 9 -
6.70% due July 15, 2011 (2006 - US$400 million, 2005 - US$400 million) 466 467
5.45% due October 1, 2012 (2006 - US$350 million , 2005 - US$350 million) 408 408
4.90% due December 1, 2014 (2006 - US$350 million, 2005 - US$350 million) 408 408
6.00% due August 15, 2016 (2006 - US$250 million, 2005 - US$nil) 291 -
7.20% due January 15, 2032 (2006 - US$400 million, 2005 - US$400 million) 466 467
6.45% due June 30, 2033 (2006 - US$350 million, 2005 - US$350 million) 408 408
5.85% due February 1, 2035 (2006 - US$350 million, 2005 - US$350 million) 408 408
6.50% due February 15, 2037 (2006 - US$450 million, 2005 - US$nil) 525 -
----------------------------------------------------------------------------------------------------------------------
$ 11,043 $ 3,321
======================================================================================================================
BANK CREDIT FACILITIES
As at December 31, 2006, the Company had in place unsecured bank credit
facilities of $7,809 million, comprised of:
o a $100 million demand credit facility;
o a $500 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $3,850 million;
o a 5-year revolving syndicated credit facility of $1,825 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (pound)15 million demand credit facility related to the Company's
North Sea operations.
The revolving syndicated credit facilities are fully revolving for a period of
five years maturing June 2011. Both facilities are extendible annually for one
year periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of ACC (note 2), the Company
executed a $3,850 million, three-year non-revolving syndicated credit facility
maturing in October 2009. This facility is subject to certain prepayment
requirements up to a maximum of $1,500 million.
During 2006, the Company obtained a $500 million credit facility repayable on
demand.
The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2006, was 4.8% (2005 - 4.0%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $338 million, including $300 million related to the Horizon Project,
were outstanding at December 31, 2006.
MEDIUM-TERM NOTES
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.
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.
Subsequent to December 31, 2006, the 7.40% unsecured debentures due March 1,
2007 were repaid.
SENIOR UNSECURED NOTES
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.
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes due December 19, 2005.
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 August 2006, the Company issued US$250 million of unsecured notes maturing
August 2016 and US$450 million of unsecured notes maturing February 2037,
bearing interest at 6.00% and 6.50%, respectively. Concurrently, the Company
entered into cross-currency interest-rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the US$250 million notes at 5.40%
and C$279 million (note 12). Proceeds from the securities issued were used to
repay bankers' acceptances under the Company's bank credit facilities.
In November 2006, the US shelf prospectus, filed in June 2005, was increased
from US$2,000 million to US$3,000 million, leaving US$2,300 million available
for issue in the United States until July 2007.
Subsequently, on March 12, 2007, the Company priced, for settlement on March 19,
2007, US$2,200 million of unsecured notes under the US shelf prospectus,
comprised of US$1,100 million of unsecured notes maturing May 2017 and US$1,100
million of unsecured notes maturing March 2038, bearing interest at 5.70% and
6.25%, respectively. Concurrently, the Company entered into cross-currency
interest-rate swaps to fix the Canadian dollar interest and principal repayment
amounts on US$1,100 million of unsecured notes due May 2017 at 5.10% and C$1,287
million. The Company also entered into a cross-currency interest-rate swap to
fix the Canadian dollar interest and principal repayment amounts on US$550
million of unsecured notes due March 2038 at 5.76% and C$644 million. Net
proceeds on the debt issue will be used to repay outstanding amounts under the
Company's bank credit facilities.
REQUIRED DEBT REPAYMENTS
Required debt repayments are as follows:
Year Repayment
--------------------------------------------------------------------------------
2007 $ 161
2008 $ 45
2009 $ 3,876
2010 $ -
2011 $ 466
Thereafter $ 3,713
--------------------------------------------------------------------------------
No debt repayments are reflected for $2,782 million of revolving bank credit
facilities due to the extendable nature of the facilities.
6. OTHER LONG-TERM LIABILITIES
2006 2005
--------------------------------------------------------------------------------
Asset retirement obligations $ 1,166 $ 1,112
Stock-based compensation 744 891
Risk management (note 12) - 885
Other 94 17
--------------------------------------------------------------------------------
2,004 2,905
Less: current portion 611 1,471
--------------------------------------------------------------------------------
$ 1,393 $ 1,434
================================================================================
ASSET RETIREMENT OBLIGATIONS
At December 31, 2006, 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 $4,497 million (2005 - $3,325
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 6.7%. A
reconciliation of the discounted asset retirement obligations is as follows:
2006 2005 2004
--------------------------------------------------------------------------------
Asset retirement obligations
Balance - beginning of year $ 1,112 $ 1,119 $ 897
Liabilities incurred 26 47 53
Liabilities acquired (note 2) 56 - 286
Liabilities settled (75) (46) (32)
Asset retirement obligation accretion 68 69 51
Revision of estimates (21) (56) (86)
Foreign exchange - (21) (50)
--------------------------------------------------------------------------------
Balance - end of year $ 1,166 $ 1,112 $ 1,119
================================================================================
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 twelve month period if all vested options are
surrendered for cash settlement.
2006 2005 2004
--------------------------------------------------------------------------------
Stock-based compensation
Balance - beginning of year $ 891 $ 323 $ 171
Stock-based compensation 139 723 249
Cash payment for options surrendered (264) (227) (80)
Transferred to common shares (101) (29) (38)
Capitalized to Horizon Project 79 101 21
--------------------------------------------------------------------------------
Balance - end of year 744 891 323
Less: current portion of stock-based
compensation 611 629 243
--------------------------------------------------------------------------------
$ 133 $ 262 $ 80
================================================================================
7. EMPLOYEE FUTURE BENEFITS
In connection with the acquisition of ACC, the Company assumed obligations to
provide defined contribution pension benefits to certain ACC employees
continuing their employment with the Company, and defined benefit pension and
other post-retirement benefits to former ACC employees, under registered and
unregistered pension plans.
The estimated future cost of providing defined benefit pension and other
post-retirement benefits to former ACC employees is actuarially determined using
management's best estimates of demographic and financial assumptions. The
discount rate of 5% used to determine accrued benefit obligations is based on a
year end market rate of interest for high-quality debt instruments with cash
flows that match the timing and amount of expected benefit payments. Company
contributions to the defined contribution plan are expensed as incurred.
The benefit obligation under the registered pension plan at December 31, 2006
was $29 million. As required by government regulations, the Company has set
aside funds with an independent trustee to meet these benefit obligations. As at
December 31, 2006, these plan assets had a fair value of $54 million. The
unregistered pension plans are unfunded and have a benefit obligation of $15
million at December 31, 2006.
8. TAXES
TAXES OTHER THAN INCOME TAX
2006 2005 2004
--------------------------------------------------------------------------------
Current petroleum revenue tax $ 196 $ 181 $ 190
Deferred petroleum revenue tax 37 (9) (45)
Provincial capital taxes and surcharges 23 22 20
--------------------------------------------------------------------------------
$ 256 $ 194 $ 165
================================================================================
INCOME TAX
The provision for income tax is as follows:
2006 2005 2004
--------------------------------------------------------------------------------
Current income tax
Current income tax - North America $ 143 $ 99 $ 101
Current income tax - North Sea 30 155 2
Current income tax -Offshore West Africa 49 32 13
--------------------------------------------------------------------------------
222 286 116
Future income tax 652 353 474
--------------------------------------------------------------------------------
Income tax $ 874 $ 639 $ 590
================================================================================
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:
2006 2005 2004
--------------------------------------------------------------------------------
Canadian statutory income tax rate 34.9% 38.0% 39.3%
--------------------------------------------------------------------------------
Income tax provision at statutory rate $ 1,275 $ 716 $ 849
Effect on income taxes of:
Non-deductible portion of Canadian
crown payments 131 309 221
Canadian resource allowance (129) (293) (270)
Large Corporations Tax (16) 16 11
Deductible UK petroleum revenue tax (82) (65) (57)
Foreign tax rate differentials 92 (1) (31)
North America income tax rate changes (438) (19) (66)
UK income tax rate changes 110 - -
Cote d'Ivoire income tax rate changes (67) - -
Non-taxable portion of foreign exchange 5 (15) (36)
Attributed Canadian Royalty Income (27) (21) (4)
Other 20 12 (27)
--------------------------------------------------------------------------------
Income tax $ 874 $ 639 $ 590
================================================================================
The following table summarizes the temporary differences that give rise to the
net future income tax asset and liability:
2006 2005
--------------------------------------------------------------------------------
Future income tax liabilities
Property, plant and equipment $ 6,088 $ 3,960
Timing of partnership items 1,394 1,646
Unrealized foreign exchange gain on
long-term debt 93 112
Risk management activities 40 -
Other 13 31
Future income tax assets
Asset retirement obligations (487) (384)
Capital loss carryforwards (85) (79)
Attributed Canadian Royalty Income - (75)
Stock-based compensation (232) (300)
Risk management activities - (304)
Deferred petroleum revenue tax (24) (59)
--------------------------------------------------------------------------------
Net future income tax liability 6,800 4,548
Less: current portion future income tax asset (163) (487)
--------------------------------------------------------------------------------
Future income tax liability $ 6,963 $ 5,035
================================================================================
During 2006, income tax rate changes resulted in a reduction of future income
tax liabilities of approximately $438 million in North America, an increase of
future income tax liabilities of approximately $110 million in the UK North Sea
and a reduction of future income tax liabilities of approximately $67 million in
Cote d'Ivoire.
During 2005, North America income tax rate changes resulted in a reduction of
future income tax liabilities of approximately $19 million.
During 2004, North America income tax rate changes resulted in a reduction of
future income tax liabilities of approximately $66 million.
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.
9. 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
2006 2005
----------------------------------------------------------------------------------------------------------------------
Number of Number of
Shares Shares
Common shares (thousands) Amount (thousands) Amount
----------------------------------------------------------------------------------------------------------------------
Balance - beginning of year 536,348 $ 2,442 536,361 $ 2,408
Issued upon exercise of stock options 2,040 21 837 9
Previously recognized liability on stock options
exercised for common shares - 101 - 29
Purchase of common shares under Normal Course Issuer Bid (485) (2) (850) (4)
----------------------------------------------------------------------------------------------------------------------
Balance - end of year 537,903 $ 2,562 536,348 $ 2,442
======================================================================================================================
NORMAL COURSE ISSUER BID
During 2006, the Company purchased 485,000 common shares for cancellation (2005
- 850,000 common shares, 2004 - 1,746,800 common shares) at an average price of
$57.33 per common share (2005 - $53.29 per common share, 2004 -$19.00 per common
share), for a total cost of $28 million (2005 - $45 million, 2004 -$33 million).
Retained earnings was reduced by $26 million (2005 - $41 million, 2004 -$26
million), representing the excess of the purchase price of the common shares
over their average carrying value.
In January 2007, the Company renewed its Normal Course Issuer Bid to purchase,
through the facilities of the Toronto Stock Exchange and the New York Stock
Exchange, during the 12-month period beginning January 24, 2007 and ending
January 23, 2008, up to 26,941,730 common shares or 5% of the outstanding common
shares of the Company then outstanding on the date of the announcement. As at
March 15, 2007, the Company had not purchased any additional shares under the
Normal Course Issuer Bid.
DIVIDEND POLICY
The Company has paid regular quarterly dividends in January, April, July and
October of each year since 2001. The dividend policy undergoes a periodic review
by the Board of Directors and is subject to change.
In March 2007, the Board of Directors set the Company's regular quarterly
dividend at $0.085 per common share (2006 - $0.075 per common share, 2005 -
$0.059 per common share).
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 were restated to retroactively reflect the share split.
STOCK OPTIONS
The Company's Option Plan provides for granting of stock options to employees.
Stock options granted under the Option Plan have terms ranging from five to 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 provides the holder the choice to purchase one common share
of the Company at the stated exercise price or receive a cash payment equal to
the difference between the stated exercise price and the market price of the
Company's common shares on the date of surrender.
The following table summarizes information relating to stock options outstanding
at December 31, 2006 and 2005:
2006 2005
-----------------------------------------------------------------------------------------------------------------------
Weighted Weighted
Stock Average Stock average
Options Exercise options exercise
(thousands) Price (thousands) price
-----------------------------------------------------------------------------------------------------------------------
Outstanding - beginning of year 30,510 $ 17.79 32,522 $ 12.37
Granted 13,084 $ 59.61 7,959 $ 32.51
Exercised for common shares (2,040) $ 10.67 (837) $ 9.81
Surrendered for cash settlement (5,180) $ 12.60 (7,523) $ 10.49
Forfeited (1,949) $ 37.51 (1,611) $ 19.36
-----------------------------------------------------------------------------------------------------------------------
Outstanding - end of year 34,425 $ 33.77 30,510 $ 17.79
-----------------------------------------------------------------------------------------------------------------------
Exercisable - end of year 9,177 $ 14.73 8,677 $ 11.21
=======================================================================================================================
The range of exercise prices of stock options outstanding and exercisable at
December 31, 2006 is as follows:
Stock Options Stock Options
Outstanding 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
-------------------------------------------------------------------------------------------------------------
$9.63 - $9.99 4,672 0.76 $ 9.71 3,603 $ 9.74
$10.00 - $19.99 9,807 2.20 $ 14.68 4,202 $ 13.78
$20.00 - $29.99 5,099 3.34 $ 25.41 957 $ 25.00
$30.00 - $39.99 1,227 3.79 $ 33.23 175 $ 33.24
$40.00 - $49.99 686 5.02 $ 46.50 69 $ 43.84
$50.00 - $59.99 7,033 4.81 $ 57.85 166 $ 55.14
$60.00 - $69.14 5,901 4.27 $ 61.70 5 $ 61.60
-------------------------------------------------------------------------------------------------------------
34,425 3.17 $ 33.77 9,177 $ 14.73
=============================================================================================================
10. FOREIGN CURRENCY TRANSLATION ADJUSTMENT
The foreign currency translation adjustment represents the unrealized loss on
the Company's net investment in self-sustaining foreign operations. Commencing
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.
2006 2005
--------------------------------------------------------------------------------
Balance - beginning of year $ (9) $ (6)
Unrealized loss on translation of net investment (4) (12)
Hedge of net investment with US dollar denominated
debt, net of tax - 9
--------------------------------------------------------------------------------
Balance - end of year $ (13) $ (9)
================================================================================
11. NET EARNINGS PER COMMON SHARE
The following table provides a reconciliation between basic and diluted amounts
per common share:
(thousands of shares) 2006 2005 2004(1)
--------------------------------------------------------------------------------
Weighted average common shares outstanding
- basic 537,339 536,650 536,223
Assumed settlement of preferred securities
with common shares(2) - 1,775 4,461
Weighted average common shares
outstanding - diluted 537,339 538,425 540,684
--------------------------------------------------------------------------------
Net earnings $ 2,524 $ 1,050 $ 1,405
Interest on preferred securities, net of tax(2) - 4 5
Revaluation of preferred securities,
net of tax (2) - (2) (4)
--------------------------------------------------------------------------------
Diluted net earnings $ 2,524 $ 1,052 $ 1,406
--------------------------------------------------------------------------------
Net earnings per common share
Basic $ 4.70 $ 1.96 $ 2.62
Diluted $ 4.70 $ 1.95 $ 2.60
================================================================================
(1) Restated to reflect two-for-one share split in May 2005.
(2) The preferred securities were redeemed in September 2005.
12. 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, 2006 and 2005, the estimated fair values of non-designated
financial derivatives were comprised as follows:
2006 2005
------------------------------------------------------------------------------------------
Risk Risk
Management Management
Mark-to- Deferred Mark-to- Deferred
Asset (liability) Market Revenue Market Revenue
------------------------------------------------------------------------------------------
Balance - beginning of year $ (877) $ (8) $ 66 $ (26)
Net cost of outstanding put options 455 - 190 -
Net change in fair value of outstanding
derivative financial instruments 1,005 - (943) -
Amortization of deferred revenue - 8 - 18
------------------------------------------------------------------------------------------
583 - (687) (8)
Add: put premium financing obligations (1) (455) - (190) -
------------------------------------------------------------------------------------------
Balance - end of year 128 - (877) (8)
Less: current portion 88 - (834) (8)
------------------------------------------------------------------------------------------
$ 40 $ - $ (43) $ -
==========================================================================================
(1) The Company has negotiated payment of put option premiums with various
counter-parties at the time of actual settlement of the respective options.
These obligations have been reflected in the net risk management asset
(liability).
Net losses (gains) from risk management activities for the years ended December
31 were as follows:
2006 2005 2004
--------------------------------------------------------------------------------
Net realized risk management loss $ 1,325 $ 1,027 $ 474
Net unrealized risk management (gain) loss (1,013) 925 (40)
--------------------------------------------------------------------------------
$ 312 $ 1,952 $ 434
================================================================================
As at December 31, 2006, the net unrecognized asset related to the estimated
fair values of derivative financial instruments designated as hedges was $222
million (December 31, 2005 - net unrecognized liability of $990 million).
FINANCIAL CONTRACTS
The Company's financial instruments recognized in the consolidated balance
sheets consist of cash and cash equivalents, 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 and the differences may be material.
The carrying value of cash and cash equivalents, 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:
2006 2005
--------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Asset (liability) Value Value Value Value
--------------------------------------------------------------------------------
Derivative financial instruments $ 583 $ 805 $ (687) $(1,700)
Fixed rate notes $ (4,410) $ (4,434) $ (3,199) $(3,367)
================================================================================
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 intended for trading or other speculative
purposes. The following summarizes instruments outstanding as at December 31,
2006:
Remaining term Volume Average price Index
-------------------------------------------------------------------------------------------------------
Crude oil
Crude oil price collars Jan 2007 - Dec 2007 15,000 bbl/d US$50.00 - US$66.25 Mayan Heavy
Jan 2007 - Dec 2007 50,000 bbl/d US$60.00 - US$71.49 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$60.00 - US$78.11 WTI
Jan 2007 - Dec 2007 50,000 bbl/d US$65.00 - US$84.52 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.05 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$60.00 - US$76.98 WTI
Crude oil puts (1) Jan 2007 - Dec 2007 100,000 bbl/d US$45.00 WTI
Jan 2007 - Dec 2007 100,000 bbl/d US$60.00 WTI
Jan 2008 - Dec 2008 50,000 bbl/d US$55.00 WTI
Brent differential swaps Jan 2007 - Dec 2007 50,000 bbl/d US$1.34 WTI/Dated Brent
-------------------------------------------------------------------------------------------------------
The cost of outstanding put options and their respective years of settlement are
as follows:
2007 2008
--------------------------------------------------------------------------------
Cost (1) ($ millions) US$ 331 US$ 59
--------------------------------------------------------------------------------
(1) Subsequent to December 31, 2006, the Company unwound 23,000 bbl/d of
US$60.00 WTI put options for the period February 2007 to December 2007, for
cash consideration of US$40 million.
Remaining term Volume Average price Index
-------------------------------------------------------------------------------------------------------
Natural gas
AECO collars Jan 2007 - Mar 2007 100,000 GJ/d C$7.00 - C$11.63 AECO
Jan 2007 - Mar 2007 200,000 GJ/d C$7.25 - C$8.38 AECO
Jan 2007 - Mar 2007 162,500 GJ/d C$7.25 - C$9.48 AECO
Jan 2007 - Mar 2007 162,500 GJ/d C$7.50 - C$8.94 AECO
Jan 2007 - Mar 2007 300,000 GJ/d C$7.50 - C$18.77 AECO
Jan 2007 - Mar 2007 400,000 GJ/d C$8.50 - C$11.22 AECO
Jan 2007 - Dec 2007 60,000 GJ/d C$8.00 - C$8.79 AECO
Apr 2007 - Oct 2007 500,000 GJ/d C$6.00 - C$10.13 AECO
Apr 2007 - Oct 2007 500,000 GJ/d C$7.00 - C$8.24 AECO
Nov 2007 - Mar 2008 400,000 GJ/d C$7.00 - C$14.08 AECO
Nov 2007 - Mar 2008 500,000 GJ/d C$7.50 - C$10.81 AECO
-------------------------------------------------------------------------------------------------------
Commodity related derivative financial instruments designated as hedges at
December 31, 2006, were all classified as cash flow hedges.
The Company's outstanding derivatives will be settled monthly based on the
applicable index pricing for the respective contract month.
In addition to the financial derivatives noted above, the Company also entered
into natural gas physical sales contracts for 325,000 GJ/d at an average fixed
price of C$9.17 per GJ at AECO for the period January to March 2007 and 300,000
GJ/d at an average fixed price of C$7.33 per GJ at AECO for the period April
2007 to October 2007.
As at December 31, 2006, the net unrealized loss related to the de-designation
of commodity cash flow hedges was $41 million. This unrealized loss will be
recognized in earnings in 2007.
INTEREST RATE RISK MANAGEMENT
The Company is exposed to interest rate price risk on its fixed rate long-term
debt and to interest rate cash flow-risk on its fioating rate long-term debt.
The Company enters into interest rate swap agreements to manage its fixed to
fioating interest rate mix on long-term debt. The interest rate swap contracts
require the periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31, 2006, the
Company had the following interest rate swap contracts outstanding:
Amount
Remaining Term ($ millions) Fixed Rate Floating Rate
--------------------------------------------------------------------------------------------------------
Interest rate
Swaps - fixed to floating Jan 2007 - Oct 2012 US$350 5.45% LIBOR (1) + 0.81%
Jan 2007 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
Swaps - floating to fixed Jan 2007 - Mar 2007 C$2 7.36% CDOR (2)
--------------------------------------------------------------------------------------------------------
(1) London Interbank Offered Rate
(2) Canadian Deposit Overnight Rate
Interest rate related derivative financial instruments designated as hedges at
December 31, 2006, were all classified as fair value hedges.
FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
The Company is exposed to foreign exchange rate risk in Canada on its US dollar
denominated debt and on product sales based on US dollar denominated benchmarks.
The Company is also exposed to foreign exchange rate risk on transactions
conducted in foreign currencies in its foreign subsidiaries and in the carrying
value of its self-sustaining foreign subsidiaries. The Company enters into
cross-currency swap agreements to manage currency exposure on US dollar
denominated long-term debt. The cross-currency swap contracts require the
periodic exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. The Company may also enter
into foreign currency denominated financial contracts to manage future US dollar
denominated crude oil and natural gas sales. The Company has designated certain
US dollar denominated debt as a hedge against its net investment in US
dollar-based self-sustaining foreign operations (note 10). At December 31, 2006,
the Company had the following cross-currency swap contracts outstanding:
Amount Exchange Interest Interest
Remaining Term ($ Millions) Rate(US$/C$) Rate(US$) Rate(C$)
--------------------------------------------------------------------------------
Currency
Swaps Jan 2007 - Aug 2016 US$250 1.116 6.00% 5.40%
--------------------------------------------------------------------------------
Cross-currency related derivative financial instruments designated as hedges at
December 31, 2006, were all classified as cash flow hedges.
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 only entering into sales contracts with 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 nonperformance by
counterparties to derivative financial instruments; however, the Company manages
this credit risk by only entering into agreements with highly rated financial
institutions and other entities. At December 31, 2006, the Company had net risk
management assets of $161 million with specific counterparties related to
derivative financial instruments.
13. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
2007 2008 2009 2010 2011 Thereafter
--------------------------------------------------------------------------------
Product transportation
and pipeline (1) $ 213 $ 193 $ 134 $ 123 $ 99 $1,042
Offshore equipment operating
leases (2) $ 77 $ 52 $ 52 $ 52 $ 50 $ 131
Offshore drilling $ 73 $ 83 $ 12 $ 12 $ 4 $ 4
Asset retirement obligations (3) $ 3 $ 3 $ 3 $ 4 $ 4 $4,480
Office leases $ 26 $ 32 $ 33 $ 34 $ 22 $ -
Electricity and other $ 51 $ 10 $ 17 $ 18 $ 1 $ -
--------------------------------------------------------------------------------
(1) The Company has 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, the annual toll payments before operating costs will be
approximately $35 million.
(2) Offshore equipment operating leases are primarily comprised of obligations
related to fioating production, storage and offtake vessels ("FPSO").
During 2006, the Company entered into an agreement to lease an additional
FPSO commencing in 2008, in connection with the planned offshore
development in Gabon, Offshore West Africa. The new FPSO lease agreement
contains cancellation provisions at the option of the Company, subject to
escalating termination payments throughout 2007 to a maximum of US$395
million.
(3) Amounts represent management's estimate of the future undiscounted payments
to settle asset retirement obligations related to resource properties,
facilities, and production platforms, based on current legislation and
industry operating practices. Amounts disclosed for the period 2007 - 2011
represent the minimum required expenditures to meet these obligations.
Actual expenditures in any particular year may exceed these minimum
amounts.
In 2005, the Board of Directors approved the construction costs for Phase 1 of
the Horizon Project, with an approved budget of $6.8 billion. Cumulative
construction spending to December 31, 2006 was approximately $4.0 billion. Final
construction costs for Phase 1 may differ from the approved budget due to
changes in the final scope and timing of completion of the project, and/or
inflationary cost pressures.
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.
14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Changes in non-cash working capital were as follows:
2006 2005 2004
--------------------------------------------------------------------------------
(Increase) decrease in non-cash
working capital
Accounts receivable and other $ (116) $ (498) $ (329)
Accounts payable 157 196 39
Accrued liabilities (582) 716 194
--------------------------------------------------------------------------------
Net change in non-cash working capital $ (541) $ 414 $ (96)
--------------------------------------------------------------------------------
Relating to:
Operating activities $ (679) $ (147) $ (14)
Financing activities 37 19 6
Investing activities 101 542 (88)
--------------------------------------------------------------------------------
$ (541) $ 414 $ (96)
--------------------------------------------------------------------------------
Other cash flow information: 2006 2005 2004
--------------------------------------------------------------------------------
Interest paid $ 262 $ 200 $ 192
Taxes paid $ 703 $ 430 $ 218
================================================================================
15. 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
------------------------------------------------------------------------------------------------------------------------------
2006 2005 2004 2006 2005 2004 2006 2005 2004
------------------------------------------------------------------------------------------------------------------------------
Segmented revenue $ 9,066 $ 8,955 $ 6,701 $ 1,616 $ 1,659 $ 1,317 $ 950 $ 485 $ 222
Less: royalties (1,203) (1,350) (1,003) (3) (3) (2) (39) (13) (6)
------------------------------------------------------------------------------------------------------------------------------
Revenue, net of royalties 7,863 7,605 5,698 1,613 1,656 1,315 911 472 216
------------------------------------------------------------------------------------------------------------------------------
Segmented expenses
Production 1,436 1,211 976 390 379 370 106 53 36
Transportation and blending 1,465 1,310 978 15 20 32 1 - -
Depletion, depreciation and amortization 1,897 1,595 1,444 297 306 265 189 104 53
Asset retirement obligation accretion 35 34 28 31 34 22 2 1 1
Realized risk management activities 1,022 870 362 303 157 112 - - -
------------------------------------------------------------------------------------------------------------------------------
Total segmented expenses 5,855 5,020 3,788 1,036 896 801 298 158 90
------------------------------------------------------------------------------------------------------------------------------
Segmented earnings before the following $ 2,008 $ 2,585 $ 1,910 $ 577 $ 760 $ 514 $ 613 $ 314 $ 126
==============================================================================================================================
Non-segmented expenses
Administration
Stock-based compensation
Interest, net
Unrealized risk management activities
Foreign exchange loss (gain)
------------------------------------------------------------------------------------------------------------------------------
Total non-segmented expenses
------------------------------------------------------------------------------------------------------------------------------
Earnings before taxes
Taxes other than income tax
Current income tax
Future income tax
------------------------------------------------------------------------------------------------------------------------------
Net earnings
==============================================================================================================================
Inter-segment
Midstream elimination and other Total
------------------------------------------------------------------------------------------------------------------------------
2006 2005 2004 2006 2005 2004 2006 2005 2004
------------------------------------------------------------------------------------------------------------------------------
Segmented revenue $ 72 $ 77 $ 68 $ (61) $ (46) $ (39) $ 11,643 $ 11,130 $ 8,269
Less: royalties - - - - - - (1,245) (1,366) (1,011)
------------------------------------------------------------------------------------------------------------------------------
Revenue, net of royalties 72 77 68 (61) (46) (39) 10,398 9,764 7,258
------------------------------------------------------------------------------------------------------------------------------
Segmented expenses
Production 23 24 20 (6) (4) (2) 1,949 1,663 1,400
Transportation and blending - - - (38) (37) (38) 1,443 1,293 972
Depletion, depreciation and amortization 8 8 7 - - - 2,391 2,013 1,769
Asset retirement obligation accretion - - - - - - 68 69 51
Realized risk management activities - - - - - - 1,325 1,027 474
------------------------------------------------------------------------------------------------------------------------------
Total segmented expenses 31 32 27 (44) (41) (40) 7,176 6,065 4,666
------------------------------------------------------------------------------------------------------------------------------
Segmented earnings before the following $ 41 $ 45 $ 41 $ (17) $ (5) $ 1 3,222 3,699 2,592
------------------------------------------------------------------------------------------------------------------------------
Non-segmented expenses
Administration 180 151 125
Stock-based compensation 139 723 249
Interest, net 140 149 189
Unrealized risk management activities (1,013) 925 (40)
Foreign exchange loss (gain) 122 (132) (91)
------------------------------------------------------------------------------------------------------------------------------
Total non-segmented expense (432) 1,816 432
------------------------------------------------------------------------------------------------------------------------------
Earnings before taxes 3,654 1,883 2,160
Taxes other than income tax 256 194 165
Current income tax 222 286 116
Future income tax 652 353 474
------------------------------------------------------------------------------------------------------------------------------
Net earnings $ 2,524 $ 1,050 $ 1,405
==============================================================================================================================
CAPITAL EXPENDITURES
2006 2005
------------------------------------------------------------------------------------------------------------------------------
Non-cash Non-cash
and and
Cash Fair Value Capitalized Cash Fair Value Capitalized
Expenditures Adjustments(1) Costs Expenditures Adjustments(1) Costs
------------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 7,936 $ 1,521 $ 9,457 $ 2,530 $ (22) $ 2,508
North Sea 646 (14) 632 387 (136) 251
Offshore West Africa 134 1 135 439 27 466
Other 11 - 11 5 - 5
------------------------------------------------------------------------------------------------------------------------------
8,727 1,508 10,235 3,361 (131) 3,230
Horizon Project (2) 3,185 - 3,185 1,499 - 1,499
Midstream 12 - 12 4 - 4
Head office 26 - 26 22 - 22
------------------------------------------------------------------------------------------------------------------------------
$ 11,950 $ 1,508 $ 13,458 $ 4,886 $ (131) $ 4,755
==============================================================================================================================
(1) Asset retirement obligations, future income tax adjustments on non-tax base
assets, and other fair value adjustments.
(2) Cash expenditures for the Horizon Project also include capitalized interest
and stock-based compensation.
Segmented property, plant and equipment, net 2006 2005
--------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 21,879 $ 14,310
North Sea 2,029 1,681
Offshore West Africa 1,204 1,253
Other 24 13
Horizon Project 5,350 2,169
Midstream 207 203
Head office 74 65
--------------------------------------------------------------------------------
$ 30,767 $ 19,694
================================================================================
Segmented assets 2006 2005
--------------------------------------------------------------------------------
Crude oil and natural gas
North America $ 23,670 $ 15,939
North Sea 2,248 1,950
Offshore West Africa 1,323 1,371
Other 46 30
Horizon Project 5,444 2,239
Midstream 355 258
Head office 74 65
--------------------------------------------------------------------------------
$ 33,160 $ 21,852
================================================================================
16. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED
ACCOUNTING PRINCIPLES
The Company's consolidated financial statements have been prepared in accordance
with Canadian GAAP. These principles conform in all material respects with US
GAAP except for those noted below. Certain 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 2006 2005 2004
--------------------------------------------------------------------------------
Net earnings - Canadian GAAP $ 2,524 $ 1,050 $ 1,405
Adjustments
Depletion, net of tax of $1 million
(2005 -$3 million, 2004 -$2 million) (A,C) 2 4 4
Stock-based compensation, net of tax
of $18 million (2005 -$nil, 2004 -$nil) (B) (40) - -
Derivative financial instruments and hedging
activities, net of tax of $15 million
(2005 -$11 million, 2004 -$7 million) (C) 117 (19) (9)
Capitalized interest, net of tax of $nil
(2005 -$nil, 2004 -$11 million) (D) - - 16
--------------------------------------------------------------------------------
Net earnings before cumulative effect of
change in accounting policy - US GAAP 2,603 1,035 1,416
Cumulative effect of change in accounting
policy, net of tax of $3 million
(2005 -$nil,2004 -$nil) (B) (8) - -
--------------------------------------------------------------------------------
Net earnings - US GAAP $ 2,595 $ 1,035 $ 1,416
--------------------------------------------------------------------------------
Net earnings before cumulative effect of
change in accounting policy - US GAAP
per common share
Basic $ 4.84 $ 1.93 $ 2.64
Diluted (F) $ 4.77 $ 1.88 $ 2.57
--------------------------------------------------------------------------------
Net earnings - US GAAP per common share
Basic $ 4.83 $ 1.93 $ 2.64
Diluted (F) $ 4.75 $ 1.88 $ 2.57
================================================================================
Comprehensive income under US GAAP would be as follows:
(millions of Canadian dollars) Notes 2006 2005 2004
--------------------------------------------------------------------------------
Net earnings - US GAAP $ 2,595 $ 1,035 $ 1,416
Derivative financial instruments and
hedging activities, net of tax of
$394 million (2005 -$312 million;
2004 -$3 million) (C) 805 (635) 8
Foreign currency translation adjustment,
net of tax of $nil (2005 -$2 million,
2004 -$4 million) (E) (4) (3) (9)
--------------------------------------------------------------------------------
Comprehensive income $ 3,396 $ 397 $ 1,415
================================================================================
The application of US GAAP would have the following effects on the consolidated
balance sheets as reported:
2006
--------------------------------------------------------------------------------
Canadian Increase
(millions of Canadian dollars) Notes GAAP (Decrease) US GAAP
--------------------------------------------------------------------------------
Current assets (C) $ 2,239 $ 131 $ 2,370
Property, plant and equipment (A,B,C,D) 30,767 89 30,856
Other long-term assets (C) 154 29 183
--------------------------------------------------------------------------------
$ 33,160 $ 249 $ 33,409
--------------------------------------------------------------------------------
Current liabilities (B) $ 3,071 $ 30 $ 3,101
Long-term debt (C) 11,043 (26) 11,017
Other long-term liabilities (B) 1,393 20 1,413
Future income tax (A,B,C,D) 6,963 21 6,984
Share capital 2,562 - 2,562
Retained earnings 8,141 45 8,186
Foreign currency translation adjustment (E) (13) 13 -
Accumulated other comprehensive income (C,E) - 146 146
--------------------------------------------------------------------------------
$ 33,160 $ 249 $ 33,409
================================================================================
2005
--------------------------------------------------------------------------------
Canadian Increase
(millions of Canadian dollars) Notes GAAP (Decrease) US GAAP
--------------------------------------------------------------------------------
Current assets (C) $ 2,051 $ 338 $ 2,389
Property, plant and equipment (A,D) 19,694 (20) 19,674
Other long-term assets 107 - 107
--------------------------------------------------------------------------------
$ 21,852 $ 318 $ 22,170
--------------------------------------------------------------------------------
Current liabilities (C) $ 3,825 $1,005 $ 4,830
Long-term debt (C) 3,321 (18) 3,303
Other long-term liabilities (C) 1,434 8 1,442
Future income tax (A,C,D) 5,035 (5) 5,030
Share capital 2,442 - 2,442
Retained earnings 5,804 (26) 5,778
Foreign currency translation adjustment (E) (9) 9 -
Accumulated other comprehensive income (C,E) - (655) (655)
--------------------------------------------------------------------------------
$ 21,852 $ 318 $ 22,170
================================================================================
NOTES:
(A) Under Canadian full cost accounting rules, costs capitalized in each cost
centre 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%. Capitalized costs and future net revenues are
determined on a net of tax basis. These differences in applying the ceiling
test to prior years resulted in the recognition of a ceiling test
impairment under US GAAP, decreasing property, plant and equipment.
For the year ended December 31, 2006, US GAAP net earnings would have
increased by $3 million (2005 - $4 million, 2004 - $4 million), net of
income taxes of $2 million (2005 - $3 million, 2004 - $2 million) to
reflect the impact of lower depletion charges.
(B) The Company accounts for its stock-based compensation liability under
Canadian GAAP using the intrinsic value method, as described in note 1(O).
Under US GAAP, effective January 1, 2006, the Company would have adopted
Financial Accounting Standards Board Statement ("FAS") 123(R), which
requires companies to account for all stock-based compensation liabilities
using the fair value method, where fair value is measured using an option
pricing model. The Company uses the Black Scholes option pricing model to
determine the fair value of its stock-based compensation liability for US
GAAP purposes. The previous US GAAP standard, FAS 123, required companies
to account for cash settled stock-based compensation liabilities using the
intrinsic value method. For the year ended December 31, 2006 US GAAP net
earnings would have decreased by $48 million, net of income taxes of $21
million, including the cumulative effect of the change in accounting policy
of $8 million, net of income taxes of $3 million. There was no difference
from Canadian GAAP prior to 2006.
(C) The Company accounts for its derivative financial instruments under
Canadian GAAP as described in note 1(P). For US GAAP purposes, 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 comprehensive income 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 are based on a combination of third
party valuations and internally derived valuations. The Company uses these
valuations to estimate the fair values of the underlying physical commodity
contracts.
For the year ended December 31, 2006, assets would have increased by $160
million (2005 -$338 million), liabilities would have decreased by $9
million (2005 - increased by $997 million), and accumulated other
comprehensive income would have increased by $159 million (2005 - decreased
by $646 million) as a result of recording all derivative financial
instruments at fair value in accordance with US GAAP.
The net earnings associated with realized and unrealized hedge
ineffectiveness on derivative contracts designated as cash flow hedges
during the year would have been $29 million, net of income taxes of $15
million (2005 - loss of $19 million, net of income taxes of $11 million;
2004 - loss of $9 million, net of income taxes of $7 million). The company
estimates that $122 million of after-tax hedging gains will be reclassified
from accumulated other comprehensive income to current period earnings
within the next twelve month period as a result of forecasted sales
occurring.
Under Canadian GAAP, the Company hedged the foreign currency component of
the US dollar purchase price of ACC using derivative financial instruments
formally designated as cash flow hedges. Under US GAAP, the foreign
currency component of a business combination is not eligible for cash flow
hedging, and therefore, the $88 million after-tax gain on the derivative
financial instruments and related depletion expense of $1 million, net of
income taxes of $1 million, would have been included in net earnings.
Accordingly, for the year ended December 31, 2006 US GAAP net earnings
would have increased in total by $117 million, net of income taxes of $15
million (2005 - decreased net earnings of $19 million, net of income taxes
of $11 million; 2004 - decreased net earnings of $9 million, net of income
taxes of $7 million) to reflect the impact of derivative financial
instruments.
(D) 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 would have been capitalized to the costs of
construction beginning in 2004. For the year ended December 31, 2004, $27
million would have been capitalized to property, plant and equipment for US
GAAP.
(E) Under US GAAP, exchange losses of $4 million, net of income taxes of $nil
(2005 -$3 million, net of income taxes of $2 million; 2004 -$9 million, net
of income taxes of $4 million) arising from the translation of
self-sustaining foreign operations would have been included in
comprehensive income.
(F) Under Canadian GAAP, the Company is not required to include potential
common shares related to stock options in the calculation of diluted
earnings per share since the Company has recorded the potential settlement
of the stock options as a liability. Under US GAAP FAS 128 "Earnings per
Share", the Company would have included potential common shares related to
stock options in the calculation of diluted earnings per share. For the
year ended December 31, 2006, an additional 8,762,000 shares would have
been included in the calculation of diluted earnings per share for US GAAP
(2005 - 13,593,000 additional shares, 2004 - 10,111,000 additional shares).
(G) Recently issued accounting standards under US GAAP:
UNCERTAIN TAX POSITIONS
In July 2006, the FASB issued Interpretation ("FIN") No. 48 "Accounting for
Uncertainty in Tax Positions - an Interpretation of FASB Statement No.
109", effective for fiscal years beginning after December 15, 2006. FIN 48
prescribes thresholds for recognizing the benefits of uncertain tax
positions in the financial statements. It also provides guidance on
derecognition, classification, interest and penalties, disclosure and
transition. The Company is currently assessing the impact of FIN 48 on its
consolidated financial statements.
TEN-YEAR REVIEW
Years ended December 31 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------------
FINANCIAL INFORMATION
(Cdn $ millions, except
per share amounts)
----------------------------------------------------------------------------------------------------------------------------------
Net earnings 2,524 1,050 1,405 1,403 539 639 758 213 31 104
Per share - basic (1) $ 4.70 $ 1.96 $ 2.62 $ 2.62 $ 1.06 $ 1.32 $ 1.62 $ 0.51 $ 0.08 $ 0.26
Cash flow from operations (2) 4,932 5,021 3,769 3,160 2,254 1,920 1,884 724 444 503
Per share - basic (1) $ 9.18 $ 9.36 $ 7.03 $ 5.88 $ 4.41 $ 3.96 $ 4.04 $ 1.74 $ 1.12 $ 1.28
----------------------------------------------------------------------------------------------------------------------------------
Capital expenditures, net of
dispositions(including
business combinations) 12,025 4,932 4,633 2,506 4,069 1,885 2,823 1,901 610 1,119
----------------------------------------------------------------------------------------------------------------------------------
Balance Sheet information
Working capital(deficiency)surplus (832) (1,774) (652) (505) (14) (6) (77) 36 58 (19)
Property, plant and equipment,
net 30,767 19,694 17,064 13,714 12,934 8,766 7,439 4,679 3,135 2,831
Total assets 33,160 21,852 18,372 14,643 13,793 9,290 8,051 4,976 3,329 3,016
Long-term debt 11,043 3,321 3,538 2,748 4,200 2,788 2,573 2,157 1,426 1,136
Shareholders' equity 10,690 8,237 7,324 6,006 4,754 3,928 3,297 1,962 1,317 1,250
----------------------------------------------------------------------------------------------------------------------------------
SHARE INFORMATION
Common shares outstanding
(thousands) 537,903 536,348 536,361 534,926 535,104 484,804 489,116 445,816 399,236 395,276
Weighted average shares
outstanding (thousands) 537,339 536,650 536,223 536,940 511,532 485,200 466,804 415,624 397,324 392,168
Dividends declared
per common share $ 0.30 $ 0.24 $ 0.20 $ 0.15 $ - $ 0.13 $ 0.10 $ - $ - $ -
----------------------------------------------------------------------------------------------------------------------------------
Trading statistics (1)
TSX-C$
Trading volume (thousands) 508,935 637,992 606,024 590,702 619,316 534,976 567,412 430,460 410,440 402,152
Share Price ($/share)
High $ 73.91 $ 62.00 $ 27.58 $ 16.81 $ 13.64 $ 13.09 $ 14.05 $ 9.65 $ 7.88 $ 11.06
Low $ 45.49 $ 24.28 $ 15.96 $ 11.30 $ 9.40 $ 8.98 $ 7.45 $ 4.95 $ 4.56 $ 7.23
Close $ 62.15 $ 57.63 $ 25.63 $ 16.34 $ 11.70 $ 9.58 $ 10.38 $ 8.81 $ 5.75 $ 7.65
NYSE -US$
Trading volume (thousands) 401,909 251,554 125,468 46,916 31,864 20,764 3,172 - - -
Share Price ($/share)
High $ 64.38 $ 54.05 $ 22.37 $ 12.85 $ 8.72 $ 8.63 $ 9.46 $ - $ - $ -
Low $ 40.29 $ 19.74 $ 11.94 $ 7.32 $ 5.89 $ 5.70 $ 6.19 $ - $ - $ -
Close $ 53.23 $ 49.62 $ 21.39 $ 12.61 $ 7.42 $ 6.10 $ 6.88 $ - $ - $ -
----------------------------------------------------------------------------------------------------------------------------------
RATIOS
Debt to book capitalization (3) 50.8% 28.7% 33.8% 32.8% 47.1% 41.7% 44.0% 52.4% 52.0% 47.6%
Return on average common
shareholders' equity,
after tax(3) 26.9% 14.3% 21.4% 25.6% 13.0% 17.7% 28.8% 13.0% 2.4% 8.8%
Daily production before royalties
per thousand common shares
(boe/d)(1) 10.8 10.3 9.6 8.5 8.2 7.4 6.6 5.0 4.7 4.5
Conventional proved and probable
reserves per common share
(boe)(1)(4) 6.4 4.8 4.3 4.0 3.3 3.1 2.9 2.4 1.9 1.7
Net asset value per common
share(1)(5) $ 56.41 $ 60.44 $ 33.13 $ 23.35 $ 19.57 $ 16.88 $ 20.54 $ 12.33 $ 8.08 $ 6.80
==================================================================================================================================
(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
basedonnet 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 60, "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 2006, $75/acre
for all years prior, less long-term debt and existing asset liabilities and
adjusted for working capital. See reserves disclosures on pages 37 to 41.
Years ended December 31 2006 2005 2004 2003 2002 2001 2000 1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------------
OPERATING INFORMATION
Conventional crude oil and NGLs (mmbbl)
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved reserves
(before royalties)
North America 1,043 785 695 672 665 644 643 554 284 257
North Sea 299 290 303 222 203 83 102 - - -
Offshore West Africa 145 148 125 106 94 61 36 - - -
----------------------------------------------------------------------------------------------------------------------------------
1,487 1,223 1,123 1,000 962 788 781 554 284 257
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable
reserves (before royalties)
North America 1,753 1,154 992 977 742 740 731 640 380 329
North Sea 421 417 415 317 277 106 134 - - -
Offshore West Africa 223 230 214 187 162 111 46 - - -
----------------------------------------------------------------------------------------------------------------------------------
2,397 1,801 1,621 1,481 1,181 957 911 640 380 329
----------------------------------------------------------------------------------------------------------------------------------
Conventional Natural gas (bcf)
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved reserves
(before royalties)
North America 4,507 3,378 3,202 3,006 3,048 2,566 2,360 2,183 1,901 1,716
North Sea 37 29 27 62 71 94 91 - - -
Offshore West Africa 69 83 81 86 90 69 65 - - -
----------------------------------------------------------------------------------------------------------------------------------
4,613 3,490 3,310 3,154 3,209 2,729 2,516 2,183 1,901 1,716
----------------------------------------------------------------------------------------------------------------------------------
Company gross proved and probable
reserves (before royalties)
North America 5,898 4,372 4,100 3,611 3,450 2,915 2,762 2,547 2,211 2,078
North Sea 93 69 57 101 89 118 114 - - -
Offshore West Africa 121 127 102 111 120 96 84 - - -
----------------------------------------------------------------------------------------------------------------------------------
6,112 4,568 4,259 3,823 3,659 3,129 2,960 2,547 2,211 2,078
----------------------------------------------------------------------------------------------------------------------------------
Total proved reserves
(before royalties) (mmboe) 2,256 1,804 1,674 1,526 1,497 1,243 1,200 918 601 543
----------------------------------------------------------------------------------------------------------------------------------
Total proved and probable reserves
(before royalties) (mmboe) 3,416 2,562 2,330 2,118 1,791 1,479 1,404 1,065 749 675
----------------------------------------------------------------------------------------------------------------------------------
Oil Sands, mining (mmbbl)
----------------------------------------------------------------------------------------------------------------------------------
Gross proved and probable reserves
(before royalties)
Bitumen 3,530 3,430 - - - - - - - -
Synthetic crude oil (1) 2,962 2,878 - - - - - - - -
----------------------------------------------------------------------------------------------------------------------------------
Daily production (before royalties)
----------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs (mbbl/d)
North America 235 222 206 175 169 167 155 87 76 71
North Sea 60 68 65 57 39 36 17 - - -
Offshore West Africa 37 23 12 10 7 3 2 - - -
----------------------------------------------------------------------------------------------------------------------------------
332 313 283 242 215 206 174 87 76 71
----------------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,468 1,416 1,330 1,245 1,204 906 793 721 673 626
North Sea 15 19 50 46 27 12 1 - - -
Offshore West Africa 9 4 8 8 1 - - - - -
----------------------------------------------------------------------------------------------------------------------------------
1,492 1,439 1,388 1,299 1,232 918 794 721 673 626
----------------------------------------------------------------------------------------------------------------------------------
Total production
(before royalties) (mboe/d) 581 553 514 459 421 359 306 207 188 175
----------------------------------------------------------------------------------------------------------------------------------
Product Pricing
----------------------------------------------------------------------------------------------------------------------------------
Average crude oil
and NGLs price ($/bbl) 53.65 46.86 37.99 32.66 31.22 23.45 31.89 22.26 11.98 18.99
Average natural
gas price ($/mcf) 6.72 8.57 6.50 6.21 3.77 5.45 4.92 2.52 2.11 1.97
==================================================================================================================================
(1) SCO reserves are based upon upgrading of the bitumen reserves. The reserves
shown for bitumen and SCO are not additive.
M A N A G E M E N T ' S D I S C U S S I O N & A N A L Y S I S
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. For
additional information refer to "Risks and Uncertainties" on page 64.
Disclosure related to future commodity pricing, production volumes, royalties,
capital expenditures and other 2007 guidance provided throughout this
Management's Discussion and Analysis, including the information provided in the
"Outlook" section on pages 69 and 70, constitutes forward looking statements as
described above.
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 probably 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 ("MD&A") 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 net asset
value. These financial measures are not defined by Canadian 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 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, 2006. 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 16 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 2006 financial
results compared to 2005 and 2004, unless otherwise indicated. In addition,
this discussion details the Company's capital program and outlook for 2007.
Certain figures related to the presentation of gross revenues and gross
transportation and blending expense provided for prior years have been
reclassified to conform to the presentation adopted in 2006.
Additional information relating to the Company, including its quarterly MD&A
for the year and three months ended December 31, 2006 and its Annual
Information Form for the year ended December 31, 2006, is available on SEDAR at
www.sedar.com.
This MD&A is dated March 15, 2007.
ABBREVIATIONS
ACC ..............................................Anadarko Canada Corporation
AECO ..................................Alberta natural gas reference location
AIF ..................................................Annual Information Form
API .............................................American Petroleum Institute
ARO .............................................Asset retirement obligations
BBL ...................................................................barrel
BBL/D ........................................................barrels per day
BOE ................................................barrels of oil equivalent
BOE/D ......................................barrels of oil equivalent per day
BRENT ............................................................Dated Brent
C$ ..........................................................Canadian dollars
FPSO .........................Floating Production, Storage and Offtake Vessel
GAAP ................................Generally accepted accounting principles
GJ..................................................................gigajoule
HEAVY DIFFERENTIAL ....................Heavy crude oil differential from WTI
HORIZON PROJECT ...................................Horizon Oil Sands Project
MCF ......................................................thousand cubic feet
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
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 strives to
meet this objective by having a defined growth and 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 allocates its capital by maintaining:
o Balance among its products, namely natural gas, light/medium 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 financing and maintenance of 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 0 degrees API oil, but receives medium
quality crude netbacks due to low production costs and low royalty rates.
The Company's three-phase crude oil marketing strategy includes:
o Blending various crude oil streams with diluents to create more
attractive feedstock;
o Supporting and participating in pipeline expansions or new additions;
and
o Supporting and participating in projects that will increase the
conversion capacity for heavy crude oil.
Operational discipline and cost control are central to the Company. 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 dominating core areas and by
maintaining high working interests in its properties.
The Company is committed to maintaining its strong financial position. The
Company believes that it has built the necessary financial capacity to complete
the Horizon Project while at the same time not compromising the delivery of its
conventional crude oil and natural gas growth opportunities. Additionally, the
Company's risk management hedge program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditures program throughout the construction period of the Horizon Project.
Strategic accretive acquisitions like the acquisition of ACC are a key
component of the Company's strategy. The Company has used a combination of
internally generated cash flows and debt financing to selectively acquire
properties generating future cash flows in its core regions. These targeted
acquisitions should provide additional free cash flow during the construction
years of the Horizon Project while still achieving targeted returns.
Highlights for the year ended December 31, 2006 are as follows:
o Achieved record levels of net earnings;
o Achieved record crude oil and NGLs and natural gas production;
o Achieved its revised annual production guidance for crude oil and NGLs
and natural gas;
o Completed the acquisition of ACC for net cash consideration of $4,641
million;
o Completed 57% of Phase 1 construction of the Horizon Project;
o Completed all major 2006 milestones on the Horizon Project before
winter's onset;
o Achieved full recovery of the Company's capital investments in the
Primrose North and South Fields;
o Received Gabonese Government approval of its development plan for the
Olowi PSC offshore Gabon and received Board of Directors sanction for
development in November 2006;
o Delivered first oil from West Espoir and completed a successful infill
drilling campaign at East Espoir in the Company's Offshore West Africa
geographic segment; and
o Purchased 485,000 common shares for a cost of $28 million under the
Company's Normal Course Issuer Bid.
NET EARNING AND CASH FLOW FROM OPERATIONS
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts) 2006 2005 2004
-------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 11,643 $ 11,130 $ 8,269
Net earnings $ 2,524 $ 1,050 $ 1,405
Per common share
- basic $ 4.70 $ 1.96 $ 2.62
- diluted $ 4.70 $ 1.95 $ 2.60
Adjusted net earnings from operations (2) $ 1,664 $ 2,034 $ 1,405
Per common share
- basic $ 3.10 $ 3.79 $ 2.62
- diluted $ 3.10 $ 3.78 $ 2.60
Cash flow from operations (3) $ 4,932 $ 5,021 $ 3,769
Per common share
- basic $ 9.18 $ 9.36 $ 7.03
- diluted $ 9.18 $ 9.33 $ 6.98
Dividends declared per common share $ 0.30 $ 0.236 $ 0.200
Total assets $ 33,160 $ 21,852 $ 18,372
Total long-term liabilities $ 19,399 $ 9,790 $ 9,196
Capital expenditures, net of dispositions $ 12,025 $ 4,932 $ 4,633
===================================================================================================================
(1) Blending costs previously netted against gross revenues in prior years have
been reclassified to transportation and blending expense to conform to the
presentation adopted in 2006.
(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) 2006 2005 2004
-------------------------------------------------------------------------------------------------------------------
Net earnings as reported $ 2,524 $ 1,050 $ 1,405
Stock-based compensation, net of tax (a) 95 481 168
Unrealized risk management (gain) loss, net of tax (b) (674) 607 (27)
Unrealized foreign exchange loss (gain), net of tax (c) 114 (85) (75)
Effect of statutory tax rate changes on future income tax
liabilities (d) (395) (19) (66)
--------------------------------------------------------------------------------------------------------------------
Adjusted net earnings from operations $ 1,664 $ 2,034 $ 1,405
====================================================================================================================
(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, or
are capitalized to the Horizon Project.
(b) Derivative financial instruments not designated as hedges are recorded at
fair value on the 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 consolidated
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. Income tax rate changes
during 2006 resulted in a reduction of future income tax liabilities of
approximately $438 million in North America, an increase of future income
tax liabilities of approximately $110 million in the UK North Sea and a
reduction of future income tax liabilities of approximately $67 million in
Offshore West Africa. Jurisdictional income tax rate changes in North
America in 2005 resulted in a reduction of future income tax liabilities of
$19 million (2004 -$66 million reduction).
(3) Cash flow from operations is a non-GAAP term that represents net earnings
adjusted for non-cash items. The Company evaluates its performance based on
cash flow from operations. The Company considers cash flow from operations
a key measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt. Cash flow from operations may not be comparable to similar
measures presented by other companies.
($ millions) 2006 2005 2004
-------------------------------------------------------------------------------------------------------------------
Net earnings $ 2,524 $ 1,050 $ 1,405
Non-cash items:
Depletion, depreciation and amortization 2,391 2,013 1,769
Asset retirement obligation accretion 68 69 51
Stock-based compensation 139 723 249
Unrealized risk management activities (1,013) 925 (40)
Unrealized foreign exchange loss (gain) 134 (103) (94)
Deferred petroleum revenue tax expense (recovery) 37 (9) (45)
Future income tax 652 353 474
-------------------------------------------------------------------------------------------------------------------
Cash flow from operations $ 4,932 $ 5,021 $ 3,769
===================================================================================================================
In 2006, the Company reported record net earnings of $2,524 million compared to
net earnings of $1,050 million in 2005 (2004 - $1,405 million). Net earnings
for the year ended December 31, 2006 included unrealized after-tax income of
$860 million related to the effects of risk management activities, statutory
tax rate changes on future income tax liabilities, fluctuations in foreign
exchange rates and stock-based compensation expense (2005 - unrealized
after-tax expenses of $984 million; 2004 - $nil). Excluding these items,
adjusted net earnings from operations for the year ended December 31, 2006
decreased to $1,664 million from $2,034 million in 2005 (2004 - $1,405 million)
primarily due to decreased natural gas pricing, increased realized risk
management losses, increased production expense and increased depletion,
depreciation and amortization expense, and the impact of a stronger Canadian
dollar relative to the US dollar. These factors were partially offset by
stronger benchmark crude oil pricing and increased crude oil and NGLs and
natural gas sales volumes.
Operating results in 2006 were impacted by the acquisition of ACC completed in
November 2006. The Company completed the acquisition of ACC, a subsidiary of
Anadarko Petroleum Corporation, for net cash consideration of $4,641 million
including working capital and other adjustments. Substantially all of ACC's
land and production base is located in Western Canada and consists of natural
gas weighted assets. The operating results of ACC have been consolidated with
the results of the Company effective November 2006. Total production from the
ACC properties averaged approximately 67,600 boe/d for the two months of
November and December, while natural gas production from the ACC properties
averaged approximately 354 mmcf/d.
The Company expects that consolidated net earnings will continue to reflect
significant volatility due to the impact of risk management activities,
stock-based compensation expense and fluctuations in foreign exchange rates.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditure program throughout the Horizon Project construction period. This
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 expected production and
up to 25% of production expected in months 25 to 48. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. In accordance with the policy, approximately 65% of expected crude
oil volumes and approximately 75% of expected natural gas volumes have been
hedged for 2007. In addition, 77,000 bbl/d of crude oil volumes are protected
by put options for 2007 at a strike price of US$60.00 per barrel. The Company
is extending its hedge program into 2008 whereby 150,000 bbl/d of crude oil
volumes have been hedged (100,000 bbl/d of price collars with a US$60.00 floor
and 50,000 bbl/d of put options with a US$55.00 strike price). In addition,
900,000 GJ/d of natural gas volumes have been hedged through the use of price
collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00 and
500,000 GJ/d with a floor of $7.50).
As effective as the Company's hedges are against reference commodity prices, a
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, the unrealized risk management asset reflects, at December
31, 2006, the implied price differentials for the non-designated hedges for
future periods. 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, 2006.
Due to the changes in crude oil and natural gas forward pricing, and the
reversal of prior year unrealized losses, the Company recorded a net unrealized
gain of $1,013 million ($674 million after-tax) on its risk management
activities for the year ended December 31, 2006 (2005 -$925 million unrealized
loss, $607 million after-tax; 2004 -$40 million unrealized gain, $27 million
after-tax). Mark-to-market unrealized gains and losses do not impact the
Company's current cash flow or its ability to finance ongoing capital programs.
The Company continues to believe that its risk management program meets its
objective of securing funding for its capital projects and does not intend to
alter its current strategy of obtaining price certainty for its crude oil and
natural gas sales.
The Company also recorded a $139 million ($95 million after-tax) stock-based
compensation expense for the year ended December 31, 2006 in connection with
the 8% increase in the Company's share price for the year ended December 31,
2006 (Company's share price as at: December 31, 2006 - C$62.15; December 31,
2005 - C$57.63; December 31, 2004 - C$25.63; December 31, 2003 - C$16.34). As
required by GAAP, the Company records a liability for potential cash payments
to settle its outstanding employee stock options, 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 at each balance sheet date to reflect the changes in the market
price of the Company's common shares and the options exercised or surrendered
in the year, with the net change recognized in earnings, or capitalized as part
of the Horizon Project during the construction period. The stock-based
compensation liability reflected the Company's potential cash liability should
all the vested options be surrendered for a cash payout at the market price on
December 31, 2006. In years when substantial share price changes occur, the
Company's net earnings are subject to significant volatility. The Company
utilizes its stock-based compensation plan to attract and retain employees in a
competitive environment. All employees participate in this plan.
Cash flow from operations for the year ended December 31, 2006 decreased
slightly to $4,932 million ($9.18 per common share) from $5,021 million ($9.36
per common share) in 2005 (2004 - $3,769 million or $7.03 per common share).
The decrease was primarily due to decreased natural gas pricing, increased
realized risk management losses, increased production expense and the impact of
a stronger Canadian dollar relative to the US dollar. These factors were
partially offset by stronger benchmark crude oil pricing and increased sales
volumes.
In 2006, the Company's average sales price per bbl of crude oil and NGLs
increased to $53.65 per bbl from $46.86 per bbl in 2005 (2004 - $37.99 per
bbl). The Company's average natural gas price decreased to $6.72 per mcf from
$8.57 per mcf in 2005 (2004 - $6.50 per mcf).
Total production of crude oil and NGLs before royalties increased to a record
331,998 bbl/d from 313,168 bbl/d in 2005 (2004 - 282,489 bbl/d). The increase
in crude oil and NGLs production primarily reflected increased production from
the Company's Primrose thermal projects, the positive results from the Pelican
Lake waterflood project, the acquisition of ACC, development of West and East
Espoir and the full year's impact of production from the Baobab Field located
offshore Cote d'Ivoire. Production from the Baobab Field commenced August 2005.
Total natural gas production before royalties increased to 1,492 mmcf/d from
1,439 mmcf/d in 2005 (2004 - 1,388 mmcf/d). The increase in natural gas
production primarily reflected additional natural gas production from the ACC
acquisition. The increase was partially offset by the production decrease due
to the effects of the Company's strategic reduction in natural gas drilling
activity and increased North America crude oil drilling, made in response to
sustained low natural gas prices and inflationary cost pressures.
Total crude oil and NGLs and natural gas production volumes before royalties
increased to 580,724 boe/d from 552,960 boe/d in 2005 (2004 - 513,835 boe/d).
OPERATING HIGHLIGHTS 2006 2005 2004
------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
Sales price (2) $ 53.65 $ 46.85 $ 37.99
Royalties 4.48 3.97 3.16
Production expense 12.29 11.17 10.05
------------------------------------------------------------------------------------------------------------------
Netback $ 36.88 $ 31.72 $ 24.78
------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
Sales price (2) $ 6.72 $ 8.57 $ 6.50
Royalties 1.29 1.75 1.35
Production expense 0.82 0.73 0.67
------------------------------------------------------------------------------------------------------------------
Netback $ 4.61 $ 6.09 $ 4.48
------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe) (1)
Sales price (2) $ 47.92 $ 48.77 $ 38.45
Royalties 5.89 6.82 5.37
Production expense 9.14 8.21 7.35
------------------------------------------------------------------------------------------------------------------
Netback $ 32.89 $ 33.74 $ 25.73
==================================================================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending 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)
-----------------------------------------------------------------------------------------------------------------------
2006 TOTAL DEC 31 SEP 30 JUN 30 MAR 31
-----------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 11,643 $ 2,826 $ 3,108 $ 3,041 $ 2,668
Net earnings $ 2,524 $ 313 $ 1,116 $ 1,038 $ 57
Net earnings per common share
- basic $ 4.70 $ 0.58 $ 2.08 $ 1.93 $ 0.11
- diluted $ 4.70 $ 0.58 $ 2.08 $ 1.93 $ 0.11
-----------------------------------------------------------------------------------------------------------------------
2005 TOTAL DEC 31 SEP 30 JUN 30 MAR 31(2)
-----------------------------------------------------------------------------------------------------------------------
Revenue, before royalties (1) $ 11,130 $ 3,319 $ 3,163 $ 2,420 $ 2,228
Net earnings (loss) $ 1,050 $ 1,104 $ 151 $ 219 $ (424)
Net earnings (loss) per common share
- basic $ 1.96 $ 2.06 $ 0.28 $ 0.41 $ (0.79)
- diluted $ 1.95 $ 2.06 $ 0.28 $ 0.41 $ (0.79)
=======================================================================================================================
(1) Blending costs previously netted against gross revenues in prior periods
have been reclassified to transportation expense to conform to the
presentation adopted in the fourth quarter of 2006.
(2) Restated to reflect two-for-one share split in May 2005.
The Company's quarterly consolidated revenues increased 27% to $2,826 million
in the fourth quarter of 2006 from $2,228 million in the first quarter of 2005.
Quarterly revenues during 2006 primarily reflected increased world benchmark
crude oil prices and increased crude oil and NGLs and natural gas sales
volumes, partially offset by decreased natural gas prices. Quarterly revenues
during 2005 primarily reflected increased world benchmark crude oil and natural
gas prices and increased crude oil and NGLs and natural gas sales volumes.
o Crude oil prices reflected demand growth and continuing geopolitical
uncertainties. Hurricane activity in the Gulf of Mexico in the third
quarter of 2005 further contributed to increased world benchmark crude
oil pricing. As a result, the Company's realized crude oil and NGLs
price increased from C$39.81 per bbl for the first quarter of 2005 to
C$47.27 per bbl for the fourth quarter of 2006. Realized natural gas
prices decreased in 2006 from 2005 primarily due to decreased heating
demand during the winter months and decreased cooling demand during the
summer months. The Company's realized natural gas price decreased
slightly from C$6.68 per mcf for the first quarter of 2005 to C$6.66
per mcf for the fourth quarter of 2006
o A stronger Canadian dollar reduced the Canadian dollar sales price the
Company received for its crude oil sales, as crude oil prices are based
on US dollar denominated benchmarks. The US / Canadian dollar average
exchange rate increased from 0.8152 for the first quarter of 2005 to
0.8781 for the fourth quarter of 2006.
o Crude oil and NGLs and natural gas sales volumes increased in 2006 over
2005. The increase in crude oil and NGLs production from 2005 primarily
reflected increased production from the Company's Primrose thermal
projects, the positive results from the Pelican Lake waterflood
project, additional production volumes from the ACC acquisition,
development of West and East Espoir and the full year's impact of
production from the Baobab Field located offshore Cote d'Ivoire.
Production from the Baobab Field commenced August 2005. The increase in
natural gas production from 2005 primarily reflected additional natural
gas production from the ACC acquisition. The increase was partially
offset by production decreases due to the effects of the Company's
strategic reduction in natural gas drilling activity and increased
North America crude oil drilling, made in response to sustained low
natural gas prices and inflationary cost pressures. In total, daily
production increased from 530,316 boe/d day in the first quarter of
2005 to 613,764 boe/d for the fourth quarter of 2006.
In addition to commodity prices and sales volumes, quarterly net earnings were
impacted by:
o Increased production expense primarily due to the ACC acquisition and
industry-wide inflationary cost pressures.
o Increased depletion, depreciation and amortization expense primarily
due to increased finding and development costs associated with crude
oil and natural gas exploration in North America, a higher depletion
base due to the acquisition of ACC and increased estimated future costs
to develop the Company's proved undeveloped reserves.
o Unrealized expense (recovery) due to the mark-to-market treatment of
the Company's stock-based compensation liability.
o Unrealized gains and losses from the mark-to-market treatment of the
Company's commodity price hedges not designated as hedges for
accounting purposes.
o Unrealized foreign exchange gains and losses due to the fluctuation of
the Canadian dollar in relation to the US dollar with respect to the US
dollar debt and working capital in North America denominated in US
dollars, as well as the re-measurement of North Sea future income tax
liabilities denominated in UK pounds sterling.
o Jurisdictional corporate tax rate changes substantively enacted in the
period.
BUSINESS ENVIRONMENT
(Yearly average) 2006 2005 2004
-------------------------------------------------------------------------------------------------
WTI benchmark price (US$/bbl) (1) $ 66.25 $ 56.61 $ 41.43
Dated Brent benchmark price (US$/bbl) $ 65.18 $ 54.45 $ 38.28
Differential to LLB blend (US$/bbl) $ 21.69 $ 20.83 $ 13.44
Differential to LLB blend as a % of WTI 33% 37% 32%
Condensate benchmark price (US$/bbl) $ 66.24 $ 57.25 $ 41.62
NYMEX benchmark price (US$/mmbtu) $ 7.26 $ 8.56 $ 6.09
AECO benchmark price (C$/GJ) $ 6.62 $ 8.05 $ 6.43
US/Canadian dollar average exchange rate (US$) $ 0.8818 $ 0.8253 $ 0.7683
=================================================================================================
(1) Refers to West Texas Intermediate crude oil prices per barrel at Cushing,
Oklahoma.
COMMODITY PRICES
World benchmark crude oil prices increased during the first part of 2006 due to
ongoing demand growth and geopolitical uncertainties. However, pricing
significantly declined later in the year, reflecting higher crude oil
inventories. In December 2006, WTI averaged US$62.09 per bbl, a decline of 21%
from the record high of US$78.40 per bbl reached in July 2006. WTI averaged
US$66.25 per bbl in 2006, an increase of 17% compared to US$56.61 per bbl in
2005 (2004 - US$41.43 per bbl).
The Company's realized crude oil price increased from 2005 as a result of the
increased WTI price and the narrower Heavy Differential. Heavy Differentials
averaged 33% for 2006 compared to 37% for 2005 (2004 - 32%). The narrowing of
the Heavy Differentials from 2005 was primarily due to reduced availability of
imported grades from Venezuela and Mexico, reduced Canadian production of heavy
crude oil and the removal of logistical constraints in accessing new markets in
the US Gulf Coast due to the Pegasus and Spearhead pipelines commencing
operations during 2006. The increase in realized crude oil prices from 2005 was
partially offset by the negative impact of a strengthening Canadian dollar
relative to the US dollar. A strengthening Canadian dollar reduces the Canadian
dollar sales price the Company receives for its crude oil sales, as crude oil
prices are based on US dollar denominated benchmarks.
The Company anticipates continued volatility in the crude oil markets as
inventory levels remain high and given the unpredictable nature of geopolitical
events.
Brent averaged US$65.18 per bbl in 2006, an increase of 20% compared to
US$54.45 per bbl in 2005 (2004 - US$38.28 per bbl). Crude oil sales contracts
for the Company's North Sea and Offshore West Africa segments are typically
based on Brent pricing, which has benefited from strong European and Asian
demand in 2006.
NYMEX natural gas prices averaged US$7.26 per mmbtu in 2006, a decrease of 15%
from US$8.56 per mmbtu in 2005 (2004 - US$6.09 per mmbtu). AECO natural gas
pricing in 2006 decreased 18% from 2005 to average C$6.62 per GJ. The decrease
in natural gas pricing in 2006 from 2005 reflected the impact of exceptionally
mild winter weather and reduced heating demand, relatively stable summer
weather and reduced cooling demand, and the continuing impact of high natural
gas inventory levels.
The Company anticipates a challenging natural gas pricing environment in the
near term given the high storage levels. Longer term natural gas pricing will
continue to be largely weather dependent.
OPERATING AND CAPITAL COSTS
Strong commodity prices in recent years have resulted in increased demand and
costs for oilfield services worldwide. This has lead to inflationary production
and capital cost pressures throughout the North American crude oil and natural
gas industry, particularly related to natural gas drilling activity and oil
sands developments. The strong commodity price environment has also impacted
costs in international basins. Specifically, the high demand for offshore
drilling rigs continues and securing rigs on commercially acceptable terms is
an ongoing challenge.
The oil and gas industry is also experiencing cost pressures related to
increasingly stringent environmental regulations, both in North America and
internationally. In addition, environmental regulations in Canada intended to
reduce greenhouse gas emissions are pending and the impact of the legislation
is uncertain at this time.
These increased cost pressures and environmental regulations may adversely
impact the Company's future net earnings, cash flow and increase the costs of
capital projects.
REVENUE, BEFORE ROYALTIES
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES
Changes due to Changes due to
($ millions) 2004 Volumes Prices Other 2005 Volumes Prices Other 2006
------------------------------------------------------------------------------------------------------------------------------
North America
Crude oil
and NGLs (1) $ 3,300 $ 170 $ 847 $ - $ 4,317 $ 198 $ 747 $ - $ 5,262
Natural gas 3,401 208 1,029 - 4,638 168 (1,002) - 3,804
------------------------------------------------------------------------------------------------------------------------------
6,701 378 1,876 - 8,955 366 (255) - 9,066
------------------------------------------------------------------------------------------------------------------------------
North Sea
Crude oil and NGLs 1,223 31 382 - 1,636 (168) 132 - 1,600
Natural gas 94 (59) (12) - 23 (4) (3) - 16
------------------------------------------------------------------------------------------------------------------------------
1,317 (28) 370 - 1,659 (172) 129 - 1,616
------------------------------------------------------------------------------------------------------------------------------
Offshore West Africa
Crude oil and NGLs 208 182 86 - 476 344 111 - 931
Natural gas 14 (6) 1 - 9 12 (2) - 19
------------------------------------------------------------------------------------------------------------------------------
222 176 87 - 485 356 109 - 950
------------------------------------------------------------------------------------------------------------------------------
Subtotal
Crude oil and NGLs 4,731 383 1,315 - 6,429 374 990 - 7,793
Natural Gas 3,509 143 1,018 - 4,670 176 (1,007) - 3,839
------------------------------------------------------------------------------------------------------------------------------
8,240 526 2,333 - 11,099 550 (17) - 11,632
------------------------------------------------------------------------------------------------------------------------------
Midstream 68 - - 9 77 - - (5) 72
------------------------------------------------------------------------------------------------------------------------------
Intersegment
eliminations
and other (2) (39) - - (7) (46) - - (15) (61)
------------------------------------------------------------------------------------------------------------------------------
Total $ 8,269 $ 526 $ 2,333 $ 2 $ 11,130 $ 550 $ (17) $ (20) $ 11,643
==============================================================================================================================
(1) Blending costs previously netted against gross revenues in prior years have
been reclassified to transportation and blending expense to conform to the
presentation adopted in 2006.
(2) Eliminates primarily internal transportation and electricity charges.
Revenue increased 5% to $11,643 million in 2006 from $11,130 million in 2005
(2004 - $8,269 million). The increase was primarily due to increased crude oil
and NGLs and natural gas sales volumes in North America and Offshore West
Africa and increased realized crude oil and NGLs prices, partially offset by
decreased realized natural gas prices.
In 2006, 22% of the Company's crude oil and natural gas revenue was generated
outside of North America (2005 - 19%; 2004 - 19%). North Sea accounted for 14%
of crude oil and natural gas revenue in 2006 (2005 - 15%; 2004 - 16%), and
Offshore West Africa accounted for 8% of crude oil and natural gas revenue in
2006 (2005 - 4%; 2004 - 3%).
ANALYSIS OF PRODUCT PRICES (1)
2006 2005 2004
------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (2)
North America $ 46.52 $ 39.62 $ 33.16
North Sea $ 72.62 $ 66.57 $ 51.37
Offshore West Africa $ 67.99 $ 59.91 $ 49.05
Company average $ 53.65 $ 46.86 $ 37.99
------------------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf) (2)
North America $ 6.77 $ 8.65 $ 6.61
North Sea $ 2.66 $ 3.17 $ 3.73
Offshore West Africa $ 5.37 $ 5.91 $ 5.25
Company average $ 6.72 $ 8.57 $ 6.50
------------------------------------------------------------------------------------------------------------------------------
Company average ($/boe) (2) $ 47.92 $ 48.77 $ 38.45
------------------------------------------------------------------------------------------------------------------------------
Percentage of revenue (excluding midstream revenue)
Crude oil and NGLs 64% 54% 54%
Natural gas 36% 46% 46%
==============================================================================================================================
(1) Net of transportation and blending costs and excluding risk management
activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.
Realized crude oil and NGLs prices increased 14% to average $53.65 per bbl in
2006 from $46.86 per bbl in 2005 (2004 - $37.99 per bbl). The increase from
2005 was due to increased benchmark crude oil prices and a narrower Heavy
Differential, partially offset by the impact of a stronger Canadian dollar.
The Company's realized natural gas price decreased 22% to average $6.72 per mcf
in 2006 from $8.57 per mcf in 2005 (2004 - $6.50 per mcf), reflecting record
levels of natural gas inventory in North America, primarily due to the impact
of exceptionally mild winter weather in 2006 that reduced heating demand and
relatively stable summer weather that reduced cooling demand.
NORTH AMERICA
North America realized crude oil prices increased 17% to average $46.52 per bbl
in 2006 from $39.62 per bbl in 2005 (2004 - $33.16 per bbl). The increase from
2005 was due to increased benchmark crude oil prices and a narrower Heavy
Differential, partially offset by the impact of a stronger Canadian dollar.
In North America, the Company 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 markets, and working with
refiners to add incremental heavy crude oil conversion capacity. During 2006,
the Company contributed approximately 136,000 bbl/d of heavy crude oil blends
to the Western Canadian Select ("WCS") stream. The Company also continues to
work with refiners to advance expansion of heavy crude oil conversion capacity,
and is working with pipeline companies to develop new capacity to the Canadian
West Coast and the US Gulf Coast where crude oil cargos can be sold on a
world-wide basis. With a view to expanding markets for its heavy crude oil, the
Company has committed to 25,000 bbl/d of capacity on the Pegasus Pipeline,
which carries crude oil to the Gulf of Mexico. The Pegasus Pipeline is made up
of a series of segments extending from Patoka, Illinois to Nederland, Texas,
near the Gulf Coast. The Company's first sales from the Pegasus Pipeline
occurred in April 2006. The Company also entered into an agreement to supply
25,000 bbl/d of heavy crude oil production to a new merchant upgrader to be
constructed in Alberta. The agreement is for a period of five years, with first
deliveries anticipated to occur in 2010 upon completion of construction of the
facilities.
North America realized natural gas prices decreased 22% to average $6.77 per
mcf in 2006 from $8.65 per mcf in 2005 (2004 - $6.61 per mcf), primarily due to
reduced seasonal heating demand and reduced summer cooling demand in 2006.
A comparison of the price received for the Company's North America production
by product type is as follows:
2006 2005 2004
-------------------------------------------------------------------------------
Wellhead price (1) (2)
Light crude oil and NGLs (C$/bbl) $ 63.09 $ 58.41 $ 45.90
Pelican Lake crude oil (C$/bbl) $ 45.02 $ 38.39 $ 32.12
Primary heavy crude oil (C$/bbl) $ 41.35 $ 33.53 $ 28.99
Thermal heavy crude oil (C$/bbl) $ 40.98 $ 32.29 $ 29.00
Natural gas (C$/mcf) $ 6.77 $ 8.65 $ 6.61
===============================================================================
(1) Net of transportation and blending costs and excluding risk management
activities.
(2) Amounts expressed on a per unit basis are based on sales volumes.
NORTH SEA
North Sea realized crude oil prices increased 9% to average $72.62 per bbl in
2006 from $66.57 per bbl 2005 (2004 - $51.37 per bbl). The increase in the
realized crude oil price from 2005 was due primarily to the impact of strong
European and Asian demand on Brent pricing, partially offset by the
strengthening Canadian dollar in 2006 compared to 2005.
OFFSHORE WEST AFRICA
Offshore West Africa realized crude oil prices increased 13% to average $67.99
per bbl in 2006 from $59.91 per bbl in 2005 (2004 - $49.05 per bbl). The
increase in the realized crude oil price from 2005 was due primarily to the
impact of strong European and Asian demand on Brent pricing, partially offset
by the strengthening Canadian dollar in 2006 compared to 2005.
CRUDE OIL INVENTORY VOLUMES
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. The related cumulative crude oil
inventory volumes by segment, which have not been recognized in revenue, were
as follows:
(bbl) 2006 2005
-------------------------------------------------------------------------------
North America, related to pipeline fill 1,097,526 484,157
North Sea, related to timing of liftings 910,796 747,141
Offshore West Africa, related to timing of liftings 113,774 412,841
-------------------------------------------------------------------------------
2,122,096 1,644,139
===============================================================================
In 2006, approximately 478,000 barrels of crude oil produced in the Company's
North America and international operations were added to inventory and excluded
from results of operations, decreasing cash flow from operations for the year
by approximately $7 million.
ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES
2006 2005 2004
-----------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 235,253 221,669 206,225
North Sea 60,056 68,593 64,706
Offshore West Africa 36,689 22,906 11,558
-----------------------------------------------------------------------------------------------
331,998 313,168 282,489
-----------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,468 1,416 1,330
North Sea 15 19 50
Offshore West Africa 9 4 8
-----------------------------------------------------------------------------------------------
1,492 1,439 1,388
-----------------------------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d) 580,724 552,960 513,835
-----------------------------------------------------------------------------------------------
Product mix
Light crude oil and NGLs 26% 26% 24%
Pelican Lake crude oil 5% 4% 4%
Primary heavy crude oil 16% 17% 19%
Thermal heavy crude oil 11% 10% 8%
Natural gas 42% 43% 45%
================================================================================================
DAILY PRODUCTION, NET OF ROYALTIES 2006 2005 2004
-----------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 205,382 191,751 180,011
North Sea 59,940 68,487 64,598
Offshore West Africa 35,212 22,293 11,221
-----------------------------------------------------------------------------------------------
300,534 282,531 255,830
-----------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,185 1,125 1,048
North Sea 15 18 50
Offshore West Africa 9 4 7
-----------------------------------------------------------------------------------------------
1,209 1,147 1,105
-----------------------------------------------------------------------------------------------
Total barrels of oil equivalent (boe/d) 502,024 473,742 440,022
===============================================================================================
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/medium crude oil and NGLs, Pelican Lake crude oil, primary
heavy crude oil and thermal heavy crude oil.
Total production of crude oil and NGLs before royalties increased 6% to 331,998
bbl/d from 313,168 bbl/d in 2005 (2004 - 282,489 bbl/d). The increase in crude
oil and NGLs production from 2005 reflected increased production from the
Company's Primrose thermal projects, the positive results from the Pelican Lake
waterflood project, additional production volumes from the ACC acquisition,
development of West and East Espoir and the full year's impact of production
from the Baobab Field located offshore Cote d'Ivoire. Production from the
Baobab Field commenced August 2005. Crude oil and NGLs production for 2006 was
in line with the Company's revised guidance of 325,000 to 336,000 bbl/d.
Natural gas production continues to represent the Company's largest product
offering. Total natural gas production before royalties increased 4% to 1,492
mmcf/d from 1,439 mmcf/d in 2005 (2004 - 1,388 mmcf/d). The increase in natural
gas production from 2005 primarily reflected additional natural gas production
from the ACC acquisition. The increase was partially offset by production
decreases due to the impact of the Company's decision to reduce natural gas
drilling activity in 2006, made in response to inflationary costs in Western
Canada. Natural gas production for 2006 was at the bottom end of the Company's
revised guidance of 1,492 to 1,501 mmcf/d.
In 2007, annual production is forecasted to average between 315,000 and 360,000
bbl/d of crude oil and NGLs and between 1,594 and 1,664 mmcf/d of natural gas.
NORTH AMERICA
North America crude oil and NGLs production in 2006 increased 6% to average
235,253 bbl/d from 221,669 bbl/d in 2005 (2004 - 206,225 bbl/d). The increase
in production from 2005 was primarily due to increased production from the
Company's Primrose thermal projects, the positive results from the Pelican Lake
waterflood project and the ACC acquisition.
North America natural gas production in 2006 increased 4% to average 1,468
mmcf/d from 1,416 mmcf/d in 2005 (2004 - 1,330 mmcf/d). The increase in natural
gas production from 2005 reflected the ACC acquisition, partially offset by
production declines due to the Company's decision to reduce natural gas
drilling activity. The ACC acquisition was completed in November with results
included from that date. To date, the ACC properties are performing as
expected.
NORTH SEA
North Sea crude oil production in 2006 was 60,056 bbl/d, a decrease of 12% from
68,593 bbl/d in 2005 (2004 - 64,706 bbl/d). Production levels in 2006 were in
line with expectations, reflecting the production effects of planned
maintenance shutdowns in the second half of 2006.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production in 2006 increased 60% to 36,689 bbl/d
from 22,906 bbl/d in 2005 (2004 - 11,558 bbl/d). The increase from 2005 was
primarily due to the impact of a full year's production from the Baobab Field,
first crude oil from West Espoir and a successful infill drilling campaign at
East Espoir. The increase was partially offset by continuing challenges with
sand and solids production at the Baobab Field that resulted in the shut in of
5 production wells. The Company does not plan to recomplete these wells until
such time as a deepwater rig can be secured on commercially acceptable terms.
ROYALTIES
2006 2005 2004
----------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 5.86 $ 5.37 $ 4.21
North Sea $ 0.13 $ 0.10 $ 0.08
Offshore West Africa $ 2.81 $ 1.62 $ 1.43
Company average $ 4.48 $ 3.97 $ 3.16
----------------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
North America $ 1.31 $ 1.78 $ 1.40
North Sea $ - $ - $ -
Offshore West Africa $ 0.22 $ 0.16 $ 0.15
Company average $ 1.29 $ 1.75 $ 1.35
----------------------------------------------------------------------------------------
Company average ($/boe) (1) $ 5.89 $ 6.82 $ 5.37
----------------------------------------------------------------------------------------
Percentage of revenue (2)
Crude oil and NGLs 8% 8% 8%
Natural gas 19% 20% 21%
Boe 12% 14% 14%
==========================================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
NORTH AMERICA
Crown Royalties on a significant portion of North America crude oil and NGLs
production falls under the oil sands royalty regime and is calculated on a
project by project basis as a percentage of gross revenue less operating,
capital and abandonment costs ("net profit"). Royalties are calculated as 1% of
gross revenues until the Company's capital investments in the applicable
project are fully recovered, at which time the royalty increases to 25% of net
profit.
Crude oil and NGLs royalties increased in 2006 primarily due to increased crude
oil prices and the full recovery of the Company's capital investments in the
Primrose North and South Fields in the second half of the year. Upon full
recovery, Crown royalty rates on the Primrose North and South Fields increased
from 1% of gross revenue to 25% of net profit. North America crude oil and NGLs
royalties per bbl are anticipated to be 14% to 16% of gross revenue in 2007, an
increase from 13% in 2006 (2005 - 14%; 2004 - 13%).
Natural gas royalties per mcf decreased from 2005 primarily due to decreased
benchmark natural gas prices. Benchmark natural gas prices decreased primarily
in response to reduced demand and increased storage levels. North America
natural gas royalties per mcf are anticipated to be 21% to 23% of gross revenue
in 2007, an increase from 19% in 2006 (2005 - 21%; 2004 - 21%).
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.
OFFSHORE WEST AFRICA
Offshore West Africa production is governed by the terms of the various
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. These revenues are
reported as sales revenue. 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. 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. The Company's
capital investments in the Espoir Field are expected to be fully recovered
early in 2007, increasing royalty rates and current income taxes in accordance
with the PSCs. The Company's capital investments in the Baobab Field are now
not expected to be fully recovered until approximately 2012 due to the ongoing
production curtailments resulting from limitations to sand screen
effectiveness.
In connection with corporate income tax rate reductions enacted by the
Government of Cote d'Ivoire during the year that were effective January 1,
2006, royalty rates as a percentage of gross revenue increased from
approximately 3% in 2005 to approximately 4% in 2006. As a result, production
volumes net of royalties decreased approximately 2% in 2006 from 2005, in
accordance with the terms of the PSC's. Royalty rates in 2007 are anticipated
to be 13% to 15% of gross revenue due to the Company's expected full recovery
of its capital investments in the Espoir Field.
PRODUCTION EXPENSE
2006 2005 2004
-------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 11.73 $ 10.49 $ 8.94
North Sea $ 17.57 $ 14.94 $ 14.03
Offshore West Africa $ 7.45 $ 6.50 $ 7.59
Company average $ 12.29 $ 11.17 $ 10.05
-------------------------------------------------------------------------------
Natural gas ($/mcf) (1)
North America $ 0.81 $ 0.71 $ 0.62
North Sea $ 1.40 $ 2.44 $ 2.07
Offshore West Africa $ 1.19 $ 1.05 $ 1.33
Company average $ 0.82 $ 0.73 $ 0.67
-------------------------------------------------------------------------------
Company average ($/boe) (1) $ 9.14 $ 8.21 $ 7.35
===============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
NORTH AMERICA
North America crude oil and NGLs production expense in 2006 increased 12% to
$11.73 per bbl from $10.49 per bbl in 2005 (2004 -$8.94 per bbl). The increase
in production expense from 2005 was primarily due to increased industry wide
service costs and increased cyclic steaming costs related to the Company's
thermal crude oil projects, due to the timing of secondary steaming cycles.
North America natural gas production expense in 2006 increased 14% to $0.81 per
mcf from $0.71 per mcf in 2005 (2004 - $0.62 per mcf), due to increased cost
pressures.
Production expense per boe in 2007 is anticipated to continue to reflect
industry wide inflationary cost pressures.
NORTH SEA
North Sea crude oil production expense increased on a per barrel basis from
2005 due to planned maintenance shutdowns, varying sales volumes on a
relatively fixed cost base and the timing of liftings from various fields.
OFFSHORE WEST AFRICA
Offshore West Africa crude oil production expense on a per barrel basis
increased from 2005 primarily due to continuing operating challenges with sand
and solids resulting in decreased production volumes at Baobab, on a relatively
fixed operating cost base.
MIDSTREAM
($ millions) 2006 2005 2004
-------------------------------------------------------------------------------
Revenue $ 72 $ 77 $ 68
Production expense 23 24 20
-------------------------------------------------------------------------------
Midstream cash flow 49 53 48
Depreciation 8 8 7
-------------------------------------------------------------------------------
Segment earnings before taxes $ 41 $ 45 $ 41
===============================================================================
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.
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
($ millions, except per boe amounts)(2) 2006 2005 2004
------------------------------------------------------------------------------
North America $ 1,897 $ 1,595 $ 1,444
North Sea 297 306 265
Offshore West Africa 189 104 53
-------------------------------------------------------------------------------
Expense $ 2,383 $ 2,005 $ 1,762
$/boe $ 11.27 $ 10.02 $ 9.37
===============================================================================
(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") expense in 2006 increased 19%
to $2,383 million from $2,005 million in 2005 (2004 - $1,762 million). The
increase in DD&A expense in total and on a boe basis in 2006 from 2005 was
primarily as a result of increased production combined with overall increases
in finding and development costs associated with crude oil and natural gas
exploration in North America, a higher depletion base due to the acquisition of
ACC, and increased estimated future costs to develop the Company's proved
undeveloped reserves.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts)(1) 2006 2005 2004
------------------------------------------------------------------------------
North America $ 35 $ 34 $ 28
North Sea 31 34 22
Offshore West Africa 2 1 1
------------------------------------------------------------------------------
Expense $ 68 $ 69 $ 51
$/boe $ 0.32 $ 0.34 $ 0.27
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Accretion expense is the increase in the carrying amount of the ARO due to the
passage of time. ARO accretion expense was comparable to 2005.
ADMINISTRATION EXPENSE
($ millions, except per boe amounts)(1) 2006 2005 2004
------------------------------------------------------------------------------
Net expense $ 180 $ 151 $ 125
$/boe $ 0.85 $ 0.75 $ 0.66
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Net administration expense in 2006 increased in total and on a boe basis from
2005 primarily due to increased insurance premiums, increased staffing and
administrative costs, costs associated with the integration of ACC, and overall
inflationary cost pressures.
STOCK-BASED COMPENSATION
($ millions) 2006 2005 2004
------------------------------------------------------------------------------
Stock-based compensation expense $ 139 $ 723 $ 249
==============================================================================
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 $139 million ($95 million after-tax) stock-based
compensation expense during 2006 in connection with the 8% appreciation in the
Company's share price (December 31, 2006 - C$62.15; December 31, 2005 -
C$57.63; December 31, 2004 - C$25.63; December 31, 2003 - C$16.34). 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 (2006 - $79 million;
2005 - $101 million; 2004 - $21 million). The stock-based compensation
liability reflected the Company's potential cash liability should all the
vested options be surrendered for a cash payout at the market price on December
31, 2006. In periods when substantial stock price changes occur, the Company is
subject to significant earnings volatility.
For the year ended December 31, 2006, the Company paid $264 million for stock
options surrendered for cash settlement (December 31, 2005 - $227 million; 2004
- $80 million).
INTEREST EXPENSE
($ millions, except per boe amounts and interest rates)(1) 2006 2005 2004
--------------------------------------------------------------------------------------------------
Interest expense, gross $ 336 $ 221 $ 189
Less: capitalized interest, Horizon Project 196 72 -
--------------------------------------------------------------------------------------------------
Interest expense, net $ 140 $ 149 $ 189
$/boe $ 0.66 $ 0.74 $ 1.01
Average effective interst rate 5.7% 5.6% 5.2%
==================================================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense increased from 2005 primarily due to increased debt
levels associated with the ACC acquisition and the financing of Horizon Project
capital expenditures. The increase was partially offset by the impact of the
strengthening Canadian dollar, which decreased interest expense on 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 intended for trading or speculative purposes.
Changes in fair value of derivative financial instruments formally 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 formally
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 derivative financial instruments designated
as 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. Realized gains or losses on these contracts are
included in risk management activities. Unrealized gains or losses on commodity
price contracts not formally documented as hedges are also 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 formally designated as hedges are included in interest
expense. Gains or losses on non-designated interest rate swap contracts are
included in risk management activities.
The Company enters into cross-currency swap agreements 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 the foreign exchange component of all cross-currency swap
contracts are included in risk management activities. Gains or losses on the
interest component of 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 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 transactions are 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 derivative financial instruments that have not been accounted
for as hedges are recognized in net earnings immediately.
($ millions) 2006 2005 2004
-------------------------------------------------------------------------------
Realized loss (gain)
Crude oil and NGLs financial instruments $ 1,395 $ 753 $ 501
Natural gas financial instruments (70) 283 5
Interest rate swaps - (9) (32)
-------------------------------------------------------------------------------
$ 1,325 $ 1,027 $ 474
-------------------------------------------------------------------------------
Unrealized (gain) loss
Crude oil and NGLs financial instruments $ (736) $ 847 $ (47)
Natural gas financial instruments (260) 77 -
Interest rate and currency swaps (17) 1 7
-------------------------------------------------------------------------------
$ (1,013) $ 925 $ (40)
-------------------------------------------------------------------------------
TOTAL $ 312 $ 1,952 $ 434
===============================================================================
The realized losses (gains) from crude oil and NGLs and natural gas financial
instruments decreased (increased) the Company's average realized prices as
follows:
2006 2005 2004
------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1) $ 11.57 $ 6.68 $ 4.85
Natural gas ($/mcf) (1) $ (0.13) $ 0.54 $ 0.01
==============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
The realized gain on non-designated interest rate swaps would have decreased
the Company's reported interest expense as follows:
($ millions, except interest rates) 2006 2005 2004
-------------------------------------------------------------------------------
Interest expense as reported $ 140 $ 149 $ 189
Less: realized risk management gain - (9) (32)
-------------------------------------------------------------------------------
$ 140 $ 140 $ 157
Average effective interest rate 5.7% 5.2% 4.4%
===============================================================================
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, the unrealized risk management asset reflected
at December 31 2006, the implied price differentials for the non-designated
hedges for future years. Due to changes in crude oil and natural gas forward
pricing and the reversal of prior year unrealized losses, the Company recorded
a net unrealized gain of $1,013 million ($674 million after-tax) on its risk
management activities in 2006 (2005 - a $925 million unrealized loss, $607
million after-tax; 2004 - a $40 million unrealized gain, $27 million after-
tax).
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, 2006.
In addition to the net risk management asset recognized on the balance sheet at
December 31, 2006, the net unrecognized asset related to the estimated fair
values of derivative financial instruments designated as hedges was $222
million (December 31, 2005 - net unrecognized liability of $990 million).
Details relating to outstanding derivative financial instruments at December
31, 2006 are disclosed in note 12 to the Company's audited annual consolidated
financial statements as at December 31, 2006.
Effective January 1, 2007, the Company will adopt new accounting standards
relating to the accounting for and disclosure of financial instruments.
Accordingly, the Company will record all of its derivative financial
instruments on the balance sheet at fair value, including those designated as
hedges. Designated hedges are currently not recognized on the balance sheet but
are disclosed in the notes to the consolidated financial statements. The
estimated effects on the Company's consolidated balance sheet are discussed in
further detail on page 68 of this MD&A.
FOREIGN EXCHANGE
($ millions) 2006 2005 2004
------------------------------------------------------------------------------
Realized foreign exchange (gain) loss $ (12) $ (29) $ 3
Unrealized foreign exchange loss (gain) 134 (103) (94)
------------------------------------------------------------------------------
Total $ 122 $ (132) $ (91)
==============================================================================
The Company's operating 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 decreased
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
increased revenue from the sale of the Company's production. Production
expenses are 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.
The realized foreign exchange loss in 2006 was primarily the result of foreign
exchange rate fluctuations on working capital items denominated in US dollars
or UK pounds sterling. The unrealized foreign exchange gain in 2006 was
primarily related to the fluctuation of the Canadian dollar in relation to the
US dollar with respect to the US dollar debt and working capital in North
America denominated in US dollars, as well as the re-measurement of North Sea
future income tax liabilities denominated in UK pounds sterling. The Canadian
dollar ended the year at US$0.8581 compared to US$0.8577 at December 31, 2005
(December 31, 2004 - US$0.8308).
In order to mitigate a portion of the volatility associated with fluctuations
in exchange rates, the Company has designated certain US dollar denominated
debt as a hedge against its net investment in US dollar based self-sustaining
foreign operations. Accordingly, translation gains and losses on this US dollar
denominated debt are included in the foreign currency translation adjustment in
Shareholders' Equity in the consolidated balance sheets.
TAXES
($ millions, except income tax rates) 2006 2005 2004
-------------------------------------------------------------------------------
Taxes other than income tax
Current $ 219 $ 203 $ 210
Deferred 37 (9) (45)
-------------------------------------------------------------------------------
Total $ 256 $ 194 $ 165
-------------------------------------------------------------------------------
Current income tax
North America $ 143 $ 99 $ 101
North Sea 30 155 2
Offshore West Africa 49 32 13
-------------------------------------------------------------------------------
Total $ 222 $ 286 $ 116
-------------------------------------------------------------------------------
Future income tax $ 652 $ 353 $ 474
Effective income tax rate 25.7%(1) 37.8%(2) 29.6%(3)
===============================================================================
(1) Includes the effect of the following:
o a charge of $110 million related to the increased supplementary charge
on oil and gas profits in the UK North Sea, substantively enacted early
in 2006.
o a recovery of $438 million due to Canadian Federal, Alberta and
Saskatchewan corporate income tax rate reductions enacted in 2006.
o a recovery of $67 million due to Offshore West Africa corporate income
tax rate reductions enacted late in 2006.
(2) Includes the effect of a $19 million recovery due to a British Columbia
corporate tax rate reduction enacted in 2005.
(3) Includes the effect of a $66 million recovery due to an Alberta corporate
tax rate reduction enacted in 2004.
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 primarily generated through partnerships, with the related income
taxes payable in a future period. North America current income taxes have been
provided on the basis of the corporate structure and available income tax
deductions and will vary depending upon the nature and amount of capital
expenditures incurred in Canada in any particular year.
Income tax rate changes during 2006 resulted in a reduction of future income
tax liabilities of approximately $438 million in North America, an increase of
future income tax liabilities of approximately $110 million in the UK North Sea
and a reduction of future income tax liabilities of approximately $67 million
in Cote d'Ivoire.
During 2005, North America income tax rate changes resulted in a reduction of
future income tax liabilities of approximately $19 million.
During 2004, North America income tax rate changes resulted in a reduction of
future income tax liabilities of approximately $66 million.
During 2003, the Canadian Federal Government enacted legislation to change the
taxation of resource income. The legislation reduces the corporate income tax
rate on resource income from 28% to 21% over five years beginning January 1,
2003. Over the same period, the deduction for resource allowance is being
phased out and a deduction for actual crown royalties paid is being phased in.
As a result in 2007, crown royalties will be fully deductible and the Company
will no longer be eligible for resource allowance in 2007 and future years.
The following table shows the effect of non-recurring benefits on income taxes:
($ millions, except income tax rates) 2006 2005 2004
---------------------------------------------------------------------------------------------
Income tax as reported
Current income tax $ 222 $ 286 $ 116
Future income tax expense 652 353 474
---------------------------------------------------------------------------------------------
874 639 590
---------------------------------------------------------------------------------------------
Provincial corporate tax rate reductions 161 19 66
Canadian Federal and foreign corporate tax rate
reductions 234 - -
---------------------------------------------------------------------------------------------
Total $ 1,269 $ 658 $ 656
Expected effective income tax rate before
non-recurring benefits 37.3% 39.0% 32.9%
=============================================================================================
The effective income tax rate for 2006 decreased slightly from 2005 due to the
effects of the phased elimination of the resource allowance, the phased
deductibility of crown royalties and foreign jurisdictional corporate tax rate
changes substantively enacted during the year. In 2007, based on budgeted
prices and the current availability of tax pools, the Company expects to be
cash taxable in Canada in the amount of $45 million to $75 million.
NET CAPITAL EXPENDITURES (1)
($ millions) 2006 2005 2004
----------------------------------------------------------------------------------------------------
Expenditures on property, plant and equipment
Net property acquisitions (dispositions) (2) $ 4,733 $ (320) $ 1,835
Land acquisition and retention 210 254 120
Seismic evaluations 130 132 89
Well drilling, completion and equipping 2,340 2,000 1,394
Pipeline and production facilities 1,314 1,295 821
----------------------------------------------------------------------------------------------------
Total net reserve replacement expenditures 8,727 3,361 4,259
----------------------------------------------------------------------------------------------------
Horizon Project
Phase 1 construction costs (3) 2,768 1,249 -
Phases 2 and 3 costs 79 - -
Capitalized interest, stock-based compensation and other (3) 338 250 291
----------------------------------------------------------------------------------------------------
Total Horizon Project 3,185 1,499 291
----------------------------------------------------------------------------------------------------
Midstream 12 4 16
Abandonments (4) 75 46 32
Head office 26 22 35
----------------------------------------------------------------------------------------------------
Total net capital expenditures $ 12,025 $ 4,932 $ 4,633
====================================================================================================
By segment
North America $ 7,936 $ 2,530 $ 3,355
North Sea 646 387 608
Offshore West Africa 134 439 295
Other 11 5 1
Horizon Project 3,185 1,499 291
Midstream 12 4 16
Abandonments (4) 75 46 32
Head office 26 22 35
----------------------------------------------------------------------------------------------------
TOTAL $ 12,025 $ 4,932 $ 4,633
====================================================================================================
(1) Net capital expenditures do not include non-cash property, plant and
equipment additions or disposals.
(2) Includes Business Combinations.
(3) Certain prior period amounts have been reclassified with respect to
stock-based compensation costs.
(4) Abandonments represent expenditures to settle AROs 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 concentrates 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 in 2006 were $12,025 million compared to $4,932
million in 2005 (2004 - $4,633 million). The increase primarily reflected the
$4,641(1) million acquisition of ACC (including working capital and other
adjustments) and continued progress on the Company's larger, future growth
projects, most notably the Horizon Project. Excluding the ACC acquisition and
the Horizon Project, net capital expenditures were $4,085 million in 2006
compared to $3,433 million in 2005, reflecting the impact of $320 million in
net property dispositions in 2005, and overall industry-wide inflationary
pressures in 2006. During 2006, the Company drilled a total of 1,738 net wells
consisting of 641 natural gas wells, 603 crude oil wells, 375 stratigraphic
test and service wells, and 119 wells that were dry. The 375 stratigraphic test
and service wells include 163 stratigraphic test wells related to the Horizon
Project. This compared to 1,882 net wells drilled in 2005 (2004 - 1,449 net
wells). The Company achieved an overall success rate of 91% in 2006, excluding
the stratigraphic test and service wells (2005 -93% and 2004 -91%).
(1) The preliminary allocation of the ACC purchase price to assets acquired
and liabilities assumed based on their fair values was as follows:
-------------------------------------------------------------------------------
Property, plant and equipment $ 6,249
Less - future income taxes (1,438)
- asset retirement costs (56)
-------------------------------------------------------------------------------
Consideration for crude oil and natural gas properties 4,755
Non-cash working capital deficit assumed and other (105)
Long-term debt assumed (9)
-------------------------------------------------------------------------------
Net purchase price - cash consideration $ 4,641
===============================================================================
NORTH AMERICA
North America, including the Horizon Project and the ACC acquisition, accounted
for approximately 94% of the total capital expenditures for the year ended
December 31, 2006 compared to approximately 83% in 2005 (2004 - 80%).
During 2006, the Company targeted 732 net natural gas wells, including 181
wells in Northeast British Columbia, 262 wells in the Northern Plains region,
177 wells in Northwest Alberta, and 112 wells in the Southern Plains region.
The Company also targeted 619 net crude oil wells during the year. The majority
of these wells were concentrated in the Company's crude oil Northern Plains
region where 292 heavy crude oil wells, 144 Pelican Lake crude oil wells, and 8
light crude oil wells were drilled. Another 114 wells targeting light crude oil
were drilled outside the Northern Plains as well as 61 thermal crude oil wells
in the Company's In-Situ Oil Sands area.
Due to significant changes in relative commodity prices between crude oil and
natural gas, the Company has taken the opportunity to access its large crude
oil drilling inventory to maximize value in both the short and long term. To
optimize netbacks in the short term, the Company will continue to focus on
drilling crude oil wells in 2007 and, accordingly, will reduce natural gas
drilling activity to manage overall capital spending. Deferred natural gas
wells will be retained in the Company's prospect inventory, and will be drilled
as natural gas commodity prices improve. Drilling on ACC acquired lands will be
optimized as part of the overall capital program.
As part of the development of the Company's In-Situ Oil Sands Assets, the
Company is continuing to develop its Primrose thermal projects. At the end of
2006, the Company had drilled 186 stratigraphic test and observation wells and
61 thermal oil wells. With first steaming for the Primrose North expansion
commencing November 2005, overall Primrose thermal production in 2006 increased
to approximately 64,000 bbl/d from 53,000 bbl/d in 2005. Initial steaming of
the projects was completed late in 2006.
In November of 2005, the Company announced a phased expansion of its In-Situ
Oil Sands assets. The next phase of this development is the Primrose East
expansion, a new facility located 15 kilometers from the existing Primrose
South steam plant and 25 kilometers from the Wolf Lake central processing
facility. This phase of the expansion is anticipated to add an additional
40,000 bbl/d and received Board of Director's sanction in 2006. Detailed
engineering and procurement is currently underway. The Company anticipates
receiving regulatory approval for Primrose East in the first half of 2007, with
drilling and construction planned to begin in the second half of 2007, and
production expected to commence in 2009.
The next phase of the Company's In-Situ Oil Sands assets expansion is the Kirby
project located 120 km north of the existing Primrose facilities. The Kirby
project is anticipated to add an additional 30,000 bbl/d of production growth.
The Company is targeting to file its formal regulatory application documents
for this project in the second half of 2007. First steaming is anticipated to
begin in 2011.
Development of new acreage and secondary recovery conversion projects at
Pelican Lake continued as expected through 2006. Drilling consisted of 144
horizontal wells, with plans to drill 132 additional horizontal wells in 2007.
The response from the polymer flood pilot continues to be positive. Based on
the results of the pilot, the Company commenced the installation of 12
additional polymer skids in 2006 as part of the approval of the commercial
polymer flood project. Pelican Lake production averaged approximately 30,000
bbl/d in 2006.
Originally announced in the fall of 2005, the scoping study for the proposed
Canadian Natural Upgrader, outside of the Horizon Project, continued during
2006 and into early 2007. The terms of reference for this study involved the
evaluation of product alternatives, location, technology, gasification and
integration with existing assets using the same disciplined approach utilized
in the Horizon Project. The next steps in this process would include a Design
Basis Memorandum ("DBM") and Engineering Design Specification ("EDS") which
would be required to be completed prior to construction and sanctioning of the
project by the Board of Directors.
Based upon the results of the scoping study, which identified growing concerns
relating to increased environmental costs for upgraders located in Canada,
inflationary capital cost pressures and a narrowing Heavy Differential in North
America, the Company has, at this point in time, deferred the DBM and EDS
pending clarification on the cost of future environmental legislation and a
more stable cost environment.
In 2007, the Company's overall drilling activity in North America is expected
to comprise approximately 423 natural gas wells and 813 crude oil wells
excluding stratigraphic and service wells.
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 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. 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.
The Horizon Project continued on schedule and on budget with construction 57%
complete at year end. The project status as at December 31, 2006 was as
follows:
o Detailed engineering was 94% complete;
o Over $5.1 billion in purchase orders and contracts have been awarded to
date;
o Several key mechanical contracts, including general mechanical
contracts for the hydrotreater and cogeneration areas, were awarded;
o Set 333 pipe rack modules, essentially forming the core infrastructure
of the plant;
o Mine overburden removal was approximately 35% complete; and
o Site preparation and underground infrastructure was completed.
In 2005, the Board of Directors of the Company approved the construction costs
for Phase 1 of the Horizon Project, with an approved budget of $6.8 billion.
Cumulative construction spending to December 31, 2006 was approximately $4.0
billion. Final construction costs for Phase 1 may differ from the approved
budget due to changes in the final scope and timing of completion of the
project, and/or inflationary cost pressures.
NORTH SEA
In 2006, the Company continued with its planned program of infill drilling,
recompletions, workovers and waterflood optimizations. During 2006, 9.2 net
wells were drilled with an additional 4 net wells drilling at year end.
The development of the Lyell Field progressed during the year with the
completion of construction, installation and tie-in of subsea infrastructure.
Tranche 1 of the Lyell Field development comprises the drilling of 4 net wells
and the workover of 2 existing wells. Production from the Lyell Field is
expected to be at full capacity in the second half of 2007.
During 2006, construction of the Columba E Raw Water Injection project
continued. The project consists of 2 injection wells.
OFFSHORE WEST AFRICA
During 2006, 5.8 net wells were drilled with 1 well drilling at year-end.
First crude oil from West Espoir commenced from 3 wells brought on-line during
2006. Late in the year 2 water injector wells were added. The West Espoir area
development drilling will continue until 2008 with producer and injector wells
being brought on-line as they are completed.
The Company purchased a 90% interest in the Olowi PSC offshore Gabon in October
2005, received Government approval of its development plan for this acquisition
early in 2006 and received Board sanction for development in November 2006.
Development plans include a FPSO handling input from 4 shallow-water producing
platforms. Late in 2006 the Company signed a lease agreement for a FPSO with a
primary term of ten years, commencing 2008.
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2006 2005 2004
-----------------------------------------------------------------------------------------------------------
Working capital deficit (1) $ 832 $ 1,774 $ 652
Long-term debt $ 11,043 $ 3,321 $ 3,538
-----------------------------------------------------------------------------------------------------------
Shareholders' equity
Share capital $ 2,562 $ 2,442 $ 2,408
Retained earnings 8,141 5,804 4,922
Foreign currency translation adjustment (13) (9) (6)
-----------------------------------------------------------------------------------------------------------
Total $ 10,690 $ 8,237 $ 7,324
-----------------------------------------------------------------------------------------------------------
Debt to book capitalization (2) 50.8% 28.7% 33.8%
Debt to market capitalization 24.8% 9.7% 21.4%
After tax return on average common shareholders' equity (3) 26.9% 14.3% 21.4%
After tax return on average capital employed (4) 17.2% 10.4% 15.3%
===========================================================================================================
(1) Calculated as current assets less current liabilities.
(2) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(3) Calculated as net earnings for the year as a percentage of average common
shareholders' equity for the year.
(4) 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, 2006 consisted primarily of
cash flow from operations, available credit facilities and access to debt
capital markets. 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 also dependent upon
these factors, as well as 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 on commercially acceptable terms, will
be sufficient to sustain its operations and support its growth strategy. The
Company's current debt ratings are BBB (high) with a negative trend by DBRS,
Baa2 with a stable outlook by Moody's Investor Services, Inc. and BBB with a
stable outlook by Standard and Poors Corporation.
At December 31, 2006, the Company had undrawn bank lines of credit of $1,115
million. Details related to the Company's credit facilities outstanding at
December 31, 2006 are disclosed in note 5 to the Company's audited annual
consolidated financial statements.
At December 31, 2006, the Company's working capital deficit was $832 million
and included the current portion of the stock-based compensation liability of
$611 million and the current portion of the net mark-to-market asset for
non-designated risk management financial derivative instruments of $88 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, 2006.
The Company believes it has the necessary financial capacity to complete the
Horizon Project, while at the same time not compromising 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, 2006, such as Baobab, Primrose and West Espoir, and the
acquisition of ACC, are anticipated to provide identified growth in production
volumes in 2007 through 2009, and generate incremental free cash flows during
this period.
Primarily due to the additional debt issued to complete the ACC acquisition,
long-term debt increased to $11,043 million at December 31, 2006, resulting in
a debt to book capitalization level of 50.8% as at December 31, 2006 (December
31, 2005 - 28.7%). While this ratio is above the 35% to 45% range targeted by
management, the Company remains committed to maintaining a strong balance sheet
and flexible capital structure, and expects its debt to book capitalization
ratio to be near the midpoint of the range in 2008. While the Company believes
that its balance sheet has the strength and flexibility to accommodate the ACC
acquisition, to ensure balance sheet strength going forward, the Company has
hedged a significant portion of its natural gas and crude oil production for
2007 and 2008 at prices that protect investment returns. In the future, the
Company may also consider the divestiture of non-strategic and non-core
properties to gain additional balance sheet flexibility.
The Company's commodity hedging program reduces the risk of volatility in
commodity price markets and supports the Company's cash flow for its capital
expenditure program throughout the Horizon Project construction period. This
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 expected production and
up to 25% of production expected in months 25 to 48. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. In accordance with the policy, approximately 65% of expected crude
oil volumes and approximately 75% of expected natural gas volumes have been
hedged for 2007. In addition, 77,000 bbl/d of crude oil volumes are protected
by put options for 2007 at a strike price of US$60.00 per barrel. The Company
is extending its hedge program into 2008 whereby 150,000 bbl/d of crude oil
volumes have been hedged (100,000 bbl/d of price collars with a US$60.00 floor
and 50,000 bbl/d of put options with a US$55.00 strike price). In addition,
900,000 GJ/d of natural gas volumes have been hedged through the use of price
collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00 and
500,000 GJ/d with a floor of $7.50).
In addition to the strategic location of the assets that ACC brings to the
Company, this acquisition allows the Company to further high grade its project
inventory and focus capital expenditures in the current highly inflationary
service market. As a result of the acquisition, the Company has reduced its
2007 conventional crude oil and natural gas capital budget by $900 million
compared to 2006 capital spending, while maintaining the capital expenditures
to complete Phase I of the Horizon Project.
LONG-TERM DEBT
The Company's long-term debt of $11,043 million at December 31, 2006 was
comprised of drawings under its bank credit facilities and debt issuances under
medium and long-term unsecured notes.
BANK CREDIT FACILITIES
As at December 31, 2006 the Company had in place unsecured bank credit
facilities of $7,809 million, comprised of:
o a $100 million demand credit facility;
o a $500 million demand credit facility;
o a 3-year non-revolving syndicated credit facility of $3,850 million;
o a 5-year revolving syndicated credit facility of $1,825 million;
o a 5-year revolving syndicated credit facility of $1,500 million; and
o a (pound)15 million demand credit facility related to the Company's
North Sea operations.
The revolving syndicated credit facilities are fully revolving for a period of
five years maturing June 2011. Both facilities are extendible annually for one
year periods at the mutual agreement of the Company and the lenders. If the
facilities are not extended, the full amount of the outstanding principal would
be repayable on the maturity date.
In conjunction with the closing of the acquisition of ACC, the Company executed
a $3,850 million, three-year non-revolving syndicated credit facility maturing
in October 2009. This facility is subject to certain prepayment requirements up
to a maximum of $1,500 million.
During 2006, the Company obtained a $500 million credit facility repayable on
demand.
The weighted average interest rate of the bank credit facilities outstanding at
December 31, 2006, was 4.8% (2005 - 4.0%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $338 million, including $300 million related to the Horizon
Project, were outstanding at December 31, 2006.
MEDIUM-TERM NOTES
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.
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.
Subsequent to December 31, 2006, the 7.40% unsecured debentures due March 1,
2007 were repaid.
SENIOR UNSECURED NOTES
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.
In December 2005, the Company repaid the US$125 million 7.69% senior unsecured
notes due December 19, 2005.
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 August 2006, the Company issued US$250 million of unsecured notes maturing
August 2016 and US$450 million of unsecured notes maturing February 2037,
bearing interest at 6.00% and 6.50%, respectively. Concurrently, the Company
entered into cross-currency interest-rate swaps to fix the Canadian dollar
interest and principal repayment amounts on the US$250 million notes at 5.40%
and C$279 million. Proceeds from the securities issued were used to repay
bankers' acceptances under the Company's bank credit facilities.
In November 2006, the US shelf prospectus, filed in June 2005, was increased
from US$2,000 million to US$3,000 million, leaving US$2,300 million available
for issue in the United States until July 2007.
Subsequently, on March 12, 2007, the Company priced, for settlement on March
19, 2007, US$2,200 million of unsecured notes under the US shelf prospectus,
comprised of US$1,100 million of unsecured notes maturing May 2017 and US$1,100
million of unsecured notes maturing March 2038, bearing interest at 5.70% and
6.25%, respectively. Concurrently, the Company entered into cross-currency
interest-rate swaps to fix the Canadian dollar interest and principal repayment
amounts on US$1,100 million of unsecured notes due May 2017 at 5.10% and
C$1,287 million. The Company also entered into a cross-currency interest-rate
swap to fix the Canadian dollar interest and principal repayment amounts on
US$550 million of unsecured notes due March 2038 at 5.76% and C$644 million.
Net proceeds on the debt issue will be used to repay outstanding amounts under
the Company's bank credit facilities.
SHARE CAPITAL
As at December 31, 2006, there were 537,903,000 common shares outstanding and
34,425,000 stock options outstanding. As at March 13, 2007, the Company had
538,970,000 common shares outstanding and 31,098,000 stock options outstanding.
During 2006, the Company purchased 485,000 common shares for cancellation (2005
- 850,000 common shares; 2004 - 873,400 common shares) at an average price of
$57.33 per common share (2005 - $53.29 per common share; 2004 -$38.01 per
common share), for a total cost of $28 million (2005 - $45 million; 2004 -$33
million) pursuant to the Normal Course Issuer Bids previously filed.
In January 2007, the Company renewed its Normal Course Issuer Bid to purchase,
through the facilities of the Toronto Stock Exchange and the New York Stock
Exchange, during the 12-month period beginning January 24, 2007 and ending
January 23, 2008, up to 26,941,730 common shares or 5% of the outstanding
common shares of the Company then outstanding on the date of the announcement.
As at March 15, 2007, the Company had not purchased any additional shares under
the Normal Course Issuer Bid.
In March 2007, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.34 per common share for 2007. The
increase represented a 13% increase from the prior year, recognizes the
stability of the Company's cash flow, and provides a return to Shareholders.
This is the seventh consecutive year in which the Company has paid dividends
and the sixth consecutive year of an increase in the distribution paid to its
Shareholders. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change. In February 2006, an increase in the annual
dividend paid by the Company was approved to $0.30 per common share for 2006.
The increase represented a 27% increase from the prior year.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to debt repayments, operating leases relating to
office space and offshore FPSOs and drilling rigs, and firm commitments for
gathering, processing and transmission services, as well as expenditures
relating to AROs. As at December 31, 2006, no entities have been consolidated
under the Canadian Institute of Chartered Accountants Handbook Accounting
Guideline 15, "Consolidation of Variable Interest Entities". The following
table summarizes the Company's commitments as at December 31, 2006:
($ millions) 2007 2008 2009 2010 2011 Thereafter
-------------------------------------------------------------------------------------------------------------------------
Product transportation and pipeline (1) $ 213 $ 193 $ 134 $ 123 $ 99 $ 1,042
Offshore equipment opeating leases (2) $ 77 $ 52 $ 52 $ 52 $ 50 $ 131
Offshore drilling $ 73 $ 83 $ 12 $ 12 $ 4 $ 4
Asset retirement obligations (3) $ 3 $ 3 $ 3 $ 4 $ 4 $ 4,480
Long-term debt (4) $ 161 $ 45 $ 3,876 $ - $ 466 $ 3,713
Office Leases $ 26 $ 32 $ 33 $ 34 $ 22 $ -
Electricity and other $ 51 $ 10 $ 17 $ 18 $ 1 $ -
=========================================================================================================================
(1) 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) Offshore equipment operating leases are primarily comprised of obligations
related to FPSOs. During 2006, the Company entered into an agreement to
lease an additional FPSO commencing in 2008, in connection with the planned
offshore development in Gabon, Offshore West Africa. The new FPSO lease
agreement contains cancellation provisions at the option of the Company,
subject to escalating termination payments throughout 2007 to a maximum of
US$395 million.
(3) Amounts represent management's estimate of the future undiscounted payments
to settle AROs related to resource properties, facilities, and production
platforms, based on current legislation and industry operating practices.
Amounts disclosed for the period 2007 - 2011 represent the minimum required
expenditures to meet these obligations. Actual expenditures in any
particular year may exceed these minimum amounts.
(4) The long-term debt represents principal repayments only. No debt repayments
are reflected for $2,782 million of revolving bank credit facilities due to
the extendable nature of the facilities.
In 2005, the Board of Directors of the Company approved the construction costs
for Phase 1 of the Horizon Project, with an approved budget of $6.8 billion.
Cumulative construction spending to December 31, 2006 was approximately $4.0
billion. Final construction costs for Phase 1 may differ from the approved
budget due to changes in the final scope and timing of completion of the
project, and/or inflationary cost pressures.
LEGAL PROCEEDINGS
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, 2006, 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, as well as 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 the 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 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 its
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.
For the year ended December 31, 2006, 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, 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 proved and probable 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
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 reserves disclosure is contained in the supplementary oil and gas
information of this Annual Report and in the Company's most recent Annual
Information Form.
(1) Conventional crude oil, NGLs and natural gas includes all of the Company's
light/medium, heavy, and thermal crude oil, natural gas, coal bed methane
and natural gas liquids 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.
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, AROs 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 Operating hazards and other difficulties inherent in the exploration
for and production and sale of crude oil and natural gas;
o Success of exploration and development activities;
o Timing and success of integrating the business and operations of
acquired companies;
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 Geopolitical risks associated with changing governmental policies,
social instability and other political, economic or diplomatic
developments in the Company's international operations; and
o Other circumstances affecting revenue and expenses.
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 only entering
into sales contracts and financial derivatives with 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.
ENVIRONMENT
The crude oil and natural gas industry is experiencing incremental increases in
costs related to environmental regulation, particularly in North America and
the North Sea. Existing and expected legislation and regulations will require
the Company to address and mitigate the effect of its activities on the
environment. This will include dismantling production facilities and
remediating damage caused by the disposal or release of specified substances.
Increasingly stringent laws and regulations may have an adverse effect on the
Company's future net earnings and cash flow from operations.
The Company's associated risk management strategies focus on working with
legislators and regulators to ensure that any new or revised policies,
legislation or regulations properly reflect a balanced approach to sustainable
development. Specific measures in response to existing or new legislation
include a focus on the Company's energy efficiency, air emissions management,
released water quality, reduced fresh water use and the minimization of the
impact on the landscape. The Company's strategy employs an Environmental
Management Plan (the "Plan"), a detailed copy of which is presented to, and
reviewed by, the Board of Directors annually. The Plan is updated quarterly at
the Directors' meetings.
The Company's Plan and operating guidelines focus on minimizing the impact of
operations while meeting regulatory requirements and internal 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:
1 Using water-based, environmentally friendly drilling muds whenever
possible;
2 Implementing cost effective ways of reducing greenhouse gas emissions
per unit of production;
3 Exercising care with respect to all waste produced through effective
waste management plans; and
4 Minimizing produced water volumes onshore and offshore through
cost-effective measures.
In 2006, the Company's capital expenditures included $75 million for
abandonment expenditures, an increase from $46 million in 2005 (2004 - $32
million).
The Company's estimated undiscounted ARO at December 31, 2006 was as follows:
Estimated ARO, undiscounted ($ millions) 2006 2005
-------------------------------------------------------------------------------
North America $ 2,826 $ 2,050
North Sea 1,543 1,185
Offshore West Africa 128 90
-------------------------------------------------------------------------------
4,497 3,325
North Sea PRT recovery (625) (370)
-------------------------------------------------------------------------------
$ 3,872 $ 2,955
===============================================================================
The estimate of the ARO is based on estimates of future costs to abandon and
restore the wells, production facilities and offshore production platforms.
Factors that affect costs include number of wells drilled, well depth and the
specific environmental legislation. The estimated costs are based on
engineering estimates using current costs in accordance with present
legislation and industry operating practice. 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. The future abandonment costs incurred in the North Sea are
expected to result in an estimated PRT recovery of $625 million (2005 - $370
million, 2004 - $600 million), as abandonment costs are an allowable deduction
in determining PRT and may be carried back to reclaim PRT previously paid. The
expected PRT recovery reduces the Company's net abandonment liability to $3,872
million (2005 - $2,955 million).
GREENHOUSE GAS AND OTHER AIR EMISSIONS
The Company is concurrently working with legislators and regulators on the
design of new greenhouse gas emission laws and regulations and is pursuing an
integrated emissions reduction strategy, to ensure the Company is able to
comply with existing and future emission reductions requirements. The Company
continues to develop strategies that will enable it to deal with the risks and
opportunities associated with new climate change policies. In addition, the
Company is working with relevant parties to ensure that new policies encourage
innovation, energy efficiency, targeted research and development while not
impacting competitiveness.
The Company continues to work with Canadian Federal and Provincial governments
on the regulatory framework for greenhouse gases for larger emitters. The
Company is actively promoting a harmonized regulatory framework between the two
levels of government. Both levels of government have indicated that existing
legislation will be amended in 2007 to create further requirements for
reporting emissions, facility-based emission intensity targets and regulatory
compliance. Compliance with emission intensity targets is expected for 2008 and
possibly a part of 2007 for larger facilities in Alberta.
Issues to be resolved include, but are not limited to: the outcome of
discussions between the Federal and Provincial Governments, the impact of
implementing legislation, the allocations of reduction obligations among
industry sectors and international developments.
Any required reductions in the greenhouse gases emitted from the Company's
operations could increase capital expenditures and operating expenses,
especially those related to the Horizon Project and the Company's other
existing and planned large oil sands projects. This may have an adverse effect
on the Company's net earnings and cash flow from operations.
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 reported results of 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, substantially all
of 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 increased 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 proved and probable crude oil and natural gas reserves.
In 2006, 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 proved reserve estimates 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 OBLIGATIONS
Under CICA Handbook Section 3110, Asset Retirement Obligations, the Company is
required to recognize a liability for the future retirement obligations
associated with its 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.
The estimated fair values of ARO 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 ARO is 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 ARO is estimated by discounting
the expected future cash flows to settle the ARO at the Company's average
credit-adjusted risk-free interest rate, which is currently 6.7%. In subsequent
periods, the ARO 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 ARO, timing of cash flows to settle the
obligation and future inflation rates could result in gains or losses on the
final settlement of the ARO.
An ARO is not recognized for assets with an indeterminate useful life (e.g.
pipeline assets) because an amount cannot be reasonably determined. An ARO for
these assets will be recorded in the first period in which the lives of these
assets are determinable.
INCOME TAXES
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 as of the
consolidated balance sheet date. Accounting for income taxes is an inherently
complex process that requires management to interpret frequently changing
regulations (e.g. changing income tax rates) and make certain judgements with
respect to the application of tax law. These interpretations and judgements
impact the current and future income tax provisions, future income tax assets
and liabilities and net earnings.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various instruments to manage its commodity price,
currency and interest rate exposures. These derivative and financial
instruments are not intended for trading or speculative purposes.
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. The cash settlement amount of
the derivative financial instruments may vary materially depending upon the
underlying crude oil and natural gas prices at the time of final settlement of
the derivative financial instruments, as compared to their mark-to-market value
at December 31, 2006.
Effective January 1, 2007, the Company will adopt new accounting standards
relating to the accounting for and disclosure of financial instruments. The
estimated effects on the Company's consolidated balance sheet are discussed in
further detail on page 68 of this MD&A.
PURCHASE PRICE ALLOCATIONS
The costs of business combinations and asset acquisitions are allocated to the
underlying 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 amounts 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
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 price
forecasts among 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
The Company's management, including the President and Chief Operating Officer
and the Chief Financial Officer and Senior Vice-President, Finance, evaluated
the effectiveness of disclosure controls and procedures as at December 31,
2006, and concluded that disclosure controls and procedures are effective to
ensure that information required to be disclosed by the Company in its annual
filings and other reports filed with securities regulatory authorities in
Canada and the United States is recorded, processed, summarized and reported
within the time periods specified and such information is accumulated and
communicated to allow timely decisions regarding required disclosures.
The President and Chief Operating Officer and the Chief Financial Officer and
Senior Vice-President, Finance also performed an assessment of internal control
over financial reporting as at December 31, 2006, and concluded that internal
control over financial reporting is effective. Further, there were no changes
in the Company's internal control over financial reporting during 2006 that
have materially affected, or are reasonably likely to materially affect,
internal controls over financial reporting.
While the Company believes that its disclosure controls and procedures and
internal controls over financial reporting provide a reasonable level of
assurance that they are effective, it recognizes that all internal control
systems have inherent limitations. Because of its inherent limitations, the
Company's internal control system may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures
may deteriorate.
NEW ACCOUNTING STANDARDS
Effective January 1, 2007, the Company will adopt the following new accounting
standards relating to the accounting for and disclosure of financial
instruments:
o Section 1530 - "Comprehensive Income" introduces the concept of
comprehensive income to Canadian GAAP. 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.
Foreign currency translation adjustment, which is currently a separate
component of shareholders' equity, will be recorded as part of
accumulated other comprehensive income.
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
will be restated only for the foreign currency translation adjustment.
o Section 3855 - "Financial Instruments - Recognition and Measurement"
prescribes when a financial asset, financial liability, or nonfinancial
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.
The Company will add all transaction costs that are directly
attributable to the acquisition or issue of a financial asset or
financial liability to the fair value of the financial asset or
financial liability. These adjustments were previously recorded in
deferred charges. Transaction costs added to the fair value of the
financial asset or financial liability will be amortized using the
effective interest method.
o Section 3865 - "Hedges" replaces Accounting Guideline 13 - "Hedging
Relationships" and EIC 128 - "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments" and specifies how hedge
accounting is to be applied and what disclosures are necessary when
hedge accounting is applied.
Adoption of this standard will require the Company to record all of its
derivative financial instruments on the balance sheet at fair value,
including those designated as hedges. Designated hedges are currently
not recognized on the balance sheet but are disclosed in the notes to
the financial statements. The adjustment to recognize the designated
hedges on the balance sheet will be recorded as an adjustment to the
opening balance of retained earnings or accumulated other comprehensive
income, as appropriate.
Subsequently, 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.
Adoption of these standards will have the following estimated effects on the
Company's consolidated balance sheet as at January 1, 2007:
($ millions)
-------------------------------------------------------------------------------
Decrease future income tax asset $ (62)
Increase current portion of other long-term assets $ 193
Decrease other long-term assets $ (16)
Decrease long-term debt $ (72)
Increase future income tax liability $ 18
Increase retained earnings $ 10
Increase foreign currency translation adjustment $ 13
Increase accumulated other comprehensive income $ 146
===============================================================================
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 2007 to average between 315,000 bbl/d
and 360,000 bbl/d of crude oil and NGLs and between 1,594 mmcf/d and 1,664
mmcf/d of natural gas.
The forecasted capital expenditures in 2007 are currently expected to be as
follows:
($ millions) 2007 Forecast
-------------------------------------------------------------------------------
North America natural gas $ 1,111
North America crude oil and NGLs 1,350
North Sea 521
Offshore West Africa 114
Property acquisitions and midstream 16
-------------------------------------------------------------------------------
3,112
Horizon Project Phase 1 construction (1) 2,610
Capitalized interest and other items 397
Horizon Project Phases 2/3 engineering 109
Canadian Natural Upgrader engineering 5
-------------------------------------------------------------------------------
Total $ 6,233
===============================================================================
(1) Forecast to be in the range of $2,410 million to $2,810 million, the final
level of expenditure will be dependent upon the ability of certain
contractors to advance portions of their efforts from 2008 into 2007 as
well as the extent of any realized cost pressures on certain isolated
portions of the Horizon Project.
NORTH AMERICA NATURAL GAS
The 2007 North America natural gas drilling program is highlighted by the
high-grading of the Company's natural gas asset base, including the properties
acquired through the ACC acquisition, as follows:
(number of wells) 2007 Forecast
-------------------------------------------------------------------------------
Northeast British Columbia 58
Northwest Alberta 123
Northern Plains 172
Southern Plains 70
-------------------------------------------------------------------------------
Total 423
===============================================================================
NORTH AMERICA CRUDE OIL AND NGLS
The 2007 North America crude oil drilling program is highlighted by continued
development of its Primrose thermal projects, Pelican Lake, and a strong
conventional heavy program, as follows:
(number of wells) 2007 Forecast
-------------------------------------------------------------------------------
Conventional heavy crude oil 369
Thermal heavy crude oil 58
Light crude oil 107
Pelican Lake crude oil 132
-------------------------------------------------------------------------------
Total 666
===============================================================================
The Company has reduced forecasted natural gas capital for 2007 by
approximately 40% from 2006 levels due to the shift in capital allocation to
higher return crude oil projects in the near term. Allocation of natural gas
capital between existing and newly acquired ACC lands will be the result of a
high-grading process focusing on the highest return projects. No changes to the
long-term natural gas plans of the Company are being contemplated.
The Company continues the disciplined development of its heavy crude oil
resources. Crude oil capital has been maintained with 2006 levels as the
Company continues to develop long-term production growth projects at Pelican
Lake and in-situ oilsands at Primrose and Kirby.
THE HORIZON PROJECT
The final level of capital expenditure on the Horizon Project will be dependent
upon the ability of certain of the contractors to advance portions of their
efforts from 2008 into 2007, as well as the extent of any realized cost
pressures on certain isolated portions of the project.
The 2007 capital forecast for the Horizon Project targets the completion of
most major plants with the commissioning process to be substantially underway.
The Ore Preparation Plant and Tailings Systems are targeted to be mechanically
complete and ready to commission
with the majority of utilities and offsite systems operational. The Upgrader is
targeted to be nearing completion, with half of the related plants completed. A
total of 156 stratigraphic test wells are targeted to be drilled on the Horizon
Project leases during 2007.
NORTH SEA
The 2007 capital forecast for the North Sea includes drilling 7.4 producer
wells and 7.2 service wells. The development of the Lyell Field is targeted for
completion in late 2007.
OFFSHORE WEST AFRICA
The 2007 capital forecast for Offshore West Africa includes drilling 3.0
producer wells and 1.2 service well at West Espoir.
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 2006, and is not necessarily indicative of future results. Each
separate line item in the sensitivity analysis shows the effect of a change in
that variable only; all other variables are held constant.
CASH FLOW CASH FLOW
FROM FROM NET NET
OPERATIONS OPERATIONS EARNINGS EARNINGS
($ millions) ($/share, basic) ($ millions) ($/share, basic)
-----------------------------------------------------------------------------------------------------------------
Price changes
Crude oil - WTI US$1.00/bbl (2)
Excluding financial derivatives $ 116 $ 0.22 $ 81 $ 0.15
Including financial derivatives $ 26-110 $ 0.05-0.21 $ 20-77 $ 0.04-0.14
Natural gas - AECO C$0.10/mcf (2)
Excluding financial derivatives $ 26 $ 0.05 $ 14 $ 0.03
Including financial derivatives $ 1-8 $ 0.00-0.02 $ 2-4 $ 0.00-0.01
Volume changes
Crude oil - 10,000 bbl/d $ 98 $ 0.18 $ 44 $ 0.08
Natural gas - 10 mmcf/d $ 17 $ 0.03 $ 6 $ 0.01
Foreign currency rate change
$0.01 change in C$ in relation to US$ (2)
Excluding financial derivatives $ 80-82 $ 0.15 $ 23-24 $ 0.04
Interest rate change - 1% $ 48 $ 0.09 $ 48 $ 0.09
=================================================================================================================
(1) The sensitivities are calculated based on 2006 fourth quarter results and
exclude mark-to-market gains (losses) on risk management activities.
(2) For details of financial instruments in place, refer to note 12 to the
Company's audited annual consolidated financial statements as at December
31, 2006.
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
Q1 Q2 Q3 Q4 2006 2005 2004
---------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America 222,955 234,780 233,440 249,565 235,253 221,669 206,225
North Sea 60,802 63,703 53,988 61,786 60,056 68,593 64,706
Offshore West Africa 39,905 40,369 34,237 32,354 36,689 22,906 11,558
---------------------------------------------------------------------------------------------------------------------------
Total 323,662 338,852 321,665 343,705 331,998 313,168 282,489
---------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d)
North America 1,411 1,448 1,416 1,594 1,468 1,416 1,330
North Sea 17 17 11 16 15 19 50
Offshore West Africa 8 10 10 10 9 4 8
---------------------------------------------------------------------------------------------------------------------------
Total 1,436 1,475 1,437 1,620 1,492 1,439 1,388
---------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent (boe/d)
North America 458,158 476,143 469,440 515,313 479,891 457,695 427,936
North Sea 63,589 66,426 55,790 64,490 62,558 71,651 73,093
Offshore West Africa 41,280 42,042 35,922 33,961 38,275 23,614 12,806
---------------------------------------------------------------------------------------------------------------------------
Total 563,027 584,611 561,152 613,764 580,724 552,960 513,835
===========================================================================================================================
PER UNIT RESULTS (1)
Q1 Q2 Q3 Q4 2006 2005 2004
------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
Sales price (2) $ 43.79 $ 60.05 $ 62.55 $ 47.27 $ 53.65 $ 46.86 $ 37.99
Royalties 3.48 5.14 5.11 4.10 4.48 3.97 3.16
Production expense 11.33 11.92 13.47 12.32 12.29 11.17 10.05
------------------------------------------------------------------------------------------------------------------------------
Netback $ 28.98 $ 42.99 $ 43.97 $ 30.85 $ 36.88 $ 31.72 $ 24.78
------------------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price (2) $ 8.30 $ 6.16 $ 5.83 $ 6.66 $ 6.72 $ 8.57 $ 6.50
Royalties 1.70 1.11 1.11 1.26 1.29 1.75 1.35
Production expense 0.80 0.80 0.84 0.86 0.82 0.73 0.67
------------------------------------------------------------------------------------------------------------------------------
Netback $ 5.80 $ 4.25 $ 3.88 $ 4.54 $ 4.61 $ 6.09 $ 4.48
------------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent ($/boe)
Sales price (2) $ 46.30 $ 50.36 $ 51.21 $ 43.91 $ 47.92 $ 48.77 $ 38.45
Royalties 6.44 5.80 5.75 5.62 5.89 6.82 5.37
Production expense 8.46 8.85 10.01 9.16 9.14 8.21 7.35
------------------------------------------------------------------------------------------------------------------------------
Netback $ 31.40 $ 35.71 $ 35.45 $ 29.13 $ 32.89 $ 33.74 $ 25.73
==============================================================================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
NETBACK ANALYSIS
($/boe) (1) 2006 2005 2004
-------------------------------------------------------------------------------
Sales price (2) $ 47.92 $ 48.77 $ 38.45
Royalties 5.89 6.82 5.37
Production expense (3) 9.14 8.21 7.35
-------------------------------------------------------------------------------
Netback 32.89 33.74 25.73
Midstream contribution (3) (0.23) (0.26) (0.26)
Administration (4) 0.85 0.75 0.66
Interest, net 0.66 0.74 1.01
Realized risk management activities 6.27 5.13 2.52
Realized foreign exchange (gain) loss (0.06) (0.15) 0.02
Taxes other than income tax - current 1.04 1.01 1.12
Current income tax - North America 0.68 0.50 0.53
Current income tax - North Sea 0.14 0.77 0.01
Current income tax - Offshore West Africa 0.23 0.17 0.07
-------------------------------------------------------------------------------
Cash flow $ 23.31 $ 25.08 $ 20.05
===============================================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending 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 2006 TOTAL 2005 Total
------------------------------------------------------------------------------------------------------------------------
TSX-C$
Trading volume (thousands) 134,487 129,036 127,022 118,390 508,935 637,992
Share price ($/share)
High $ 73.91 $ 72.70 $ 63.30 $ 63.50 $ 73.91 $ 62.00
Low $ 57.75 $ 50.78 $ 47.28 $ 45.49 $ 45.49 $ 24.28
Close $ 64.90 $ 61.72 $ 50.94 $ 62.15 $ 62.15 $ 57.63
Market capitalization
at December 31 ($ millions) $ 33,431 $ 30,910
------------------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands) 537,903 536,348
------------------------------------------------------------------------------------------------------------------------
NYSE - US$
Trading volume (thousands) 78,836 102,472 101,438 119,163 401,909 251,554
Share price ($/share)
High $ 64.38 $ 63.93 $ 56.68 $ 55.48 $ 64.38 $ 54.05
Low $ 49.62 $ 45.67 $ 42.38 $ 40.29 $ 40.29 $ 19.74
Close $ 55.39 $ 55.38 $ 45.58 $ 53.23 $ 53.23 $ 49.62
Market capitalization at
December 31 ($ millions) $ 28,633 $ 26,614
------------------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands) 537,903 536,348
========================================================================================================================
MANAGEMENT'S REPORT
The accompanying consolidated financial statements and all other information
contained elsewhere in this annual report are the responsibility of management.
The consolidated financial statements have been prepared by management in
accordance with the accounting policies described in the accompanying notes.
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 presented 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 and recorded, 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 audit and provide their independent audit
opinions on the following:
o the Company's consolidated financial statements as at December 31,
2006;
o the effectiveness of the Company's internal control over financial
reporting as at December 31, 2006; and
o management's assessment of the Company's internal control over
financial reporting as at December 31, 2006.
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, which is comprised of non-management directors. The Audit
Committee meets with management and the independent 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 Chief Financial Officer & Vice President, Finance & Accounting
Operating Officer Senior Vice-President, Finance
March 15, 2007
Calgary, Alberta, Canada
MANAGEMENT'S ASSESSMENT OF INTERNAL
CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal
control over financial reporting for the Company as defined in Rule 15(d)-15(f)
under the United States Securities Exchange Act of 1934, as amended.
Management, together with the Company's President and Chief Operating Officer
and the Company's Chief Financial Officer and Senior Vice-President, Finance,
performed an assessment of the Company's internal control over financial
reporting based on the criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
Based on the assessment, management, together with the Company's President and
Chief Operating Officer and the Company's Chief Financial Officer and Senior
Vice-President, Finance, has concluded that the Company's internal control over
financial reporting is effective as at December 31, 2006. Management recognizes
that all internal control systems have inherent limitations. Because of its
inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate.
Management's assessment of the effectiveness of the Company's internal control
over financial reporting as at December 31, 2006, has been audited by
PricewaterhouseCoopers LLP, independent auditors, as stated in their report
presented with the audited consolidated financial statements.
/s/ Steve W. Laut /s/ Douglas A. Proll
--------------------- ----------------------------
Steve W. Laut Douglas A. Proll, CA
President & Chief Operating Officer Chief Financial Officer &
Senior Vice-President, Finance
March 15, 2007
Calgary, Alberta, Canada
I N D E P E N D E N T A U D I T O R ' S R E P O R T
To the Shareholders of Canadian Natural Resources Limited
We have completed an integrated audit of the consolidated financial statements
and internal control over financial reporting of Canadian Natural Resources
Limited (the "Company") as of December 31, 2006 and audits of its December 31,
2005 and December 31, 2004 consolidated financial statements. Our opinions,
based on our audits, are presented below.
CONSOLIDATED FINANCIAL STATEMENTS
We have audited the accompanying consolidated balance sheets of the Company as
of December 31, 2006 and December 31, 2005, and the related consolidated
statements of earnings, retained earnings and cash flows for each of the three
years in the period ended December 31, 2006. These 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 audit of the Company's financial statements as of December 31,
2006 and for the year then ended in accordance with Canadian generally accepted
auditing standards and the standards of the Public Company Accounting Oversight
Board (United States). We conducted our audits of the Company's financial
statements as of December 31, 2005 and for each of the two years in the period
ended December 31, 2005 in accordance with Canadian generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit of financial statements includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. A financial statement audit also includes assessing the accounting
principles used and significant estimates made by management, and evaluating
the overall financial statement presentation.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of the Company as of
December 31, 2006 and December 31, 2005 and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2006 in accordance with Canadian generally accepted accounting principles.
INTERNAL CONTROL OVER FINANCIAL REPORTING
We have also audited management's assessment, included in the accompanying
management's assessment of internal control over financial reporting, that the
Company maintained effective internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal Control
-Integrated Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). The Company's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express opinions on management's assessment and on the
effectiveness of the Company's internal control over financial reporting based
on our audit.
We conducted our audit of internal control over financial reporting in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether effective internal control over
financial reporting was maintained in all material respects. An audit of
internal control over financial reporting includes obtaining an understanding
of internal control over financial reporting, evaluating management's
assessment, testing and evaluating the design and operating effectiveness of
internal control, and performing such other procedures as we consider necessary
in the circumstances. We believe that our audit provides a reasonable basis for
our opinions.
A company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the
company; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the company's assets that could have a material effect on the financial
statements.
Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that the Company maintained effective
internal control over financial reporting as of December 31, 2006 is fairly
stated, in all material respects, based on criteria established in Internal
Control -- Integrated Framework issued by the COSO. Furthermore, in our
opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2006 based on criteria
established in Internal Control -- Integrated Framework issued by the COSO.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada
March 15, 2007
ADDITIONAL DISCLOSURE
DISCLOSURE CONTROLS AND PROCEDURES
As of the end of the registrant's fiscal year ended December 31, 2006, 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 management with the participation of 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 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.
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The required disclosure is included in the "Management Report" that accompanies
the Registrant's Management's Discussion and Analysis for the fiscal year ended
December 31, 2006, filed as part of this Annual Report on Form 40-F.
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
The required disclosure is included in the "Auditors' Report" that accompanies
the Registrant's Management's Discussion and Analysis for the fiscal year ended
December 31, 2006, filed as part of this Annual Report on Form 40-F.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
During the fiscal year ended December 31, 2006, there were no changes in
Canadian Natural's internal controls over financial reporting that have
materially affected, or are reasonably likely to materially affect, Canadian
Natural'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
rules of the New York Stock Exchange.
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 officer, 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 amendments, waivers
or implicit waivers to the Code of Ethics in whole or in part were asked for or
granted to any director, senior officer or employee in 2006.
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, 2006 and December 31, 2005, for
professional services rendered by PwC for the audit of its internal controls
and 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 not to exceed C$3,126,287 for 2006 and were
C$1,227,835 for 2005.
AUDIT-RELATED FEES: The aggregate fees billed for each of the last two
fiscal years of Canadian Natural, ending December 31, 2006 and December 31,
2005, for audit-related services by PwC consisting of debt covenant compliance
and Crown Royalty Statements, were not to exceed $121,353 for 2006 and were
$266,923 for 2005. 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, 2006 and December 31, 2005, 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 2006 were not to exceed $134,025 for 2006 and were $39,331
for 2005. 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, 2006 and December 31,
2005 for other services were not to exceed $9,516 for 2006 and were $7,290 for
2005. The fees for other services paid in 2006 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
2
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 2006.
3
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 63 of Canadian Natural's Management's Discussion
and Analysis of Financial Condition and Results of Operations for the fiscal
year ended December 31, 2006, filed herewith, under the caption "Commitments
and Off Balance Sheet Arrangements".
CONTRACTUAL OBLIGATIONS
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, Canadian Natural has entered into various
commitments that will have an impact on Canadian Natural's future operations.
These commitments primarily relate to debt repayments, operating leases
relating to office space and offshore FPSOs and drilling rigs, and firm
commitments for gathering, processing and transmission services, as well as
expenditures relating to asset retirement obligations. As at December 31, 2006,
no entities were consolidated under the Canadian Institute of Chartered
Accountants Handbook Accounting Guideline 15, "Consolidation of Variable
Interest Entities". The following table summarizes Canadian Natural's
commitments as at December 31, 2006:
($ millions) 2007 2008 2009 2010 2011 Thereafter
--------------------------------------------------------------------------------------------------------------
Product transportation and
pipeline (1) $ 213 $ 193 $ 134 $ 123 $ 99 $ 1,042
Offshore equipment operating
leases (2) $ 77 $ 52 $ 52 $ 52 $ 50 $ 131
Offshore drilling $ 73 $ 83 $ 12 $ 12 $ 4 $ 4
Asset retirement obligations (3) $ 3 $ 3 $ 3 $ 4 $ 4 $ 4,480
Long-term debt (4) $ 161 $ 45 $ 3,876 $ - $ 466 $ 3,713
Office leases $ 26 $ 32 $ 33 $ 34 $ 22 $ -
Electricity and other $ 51 $ 10 $ 17 $ 18 $ 1 $ -
==============================================================================================================
(1) CANADIAN NATURAL 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 CANADIAN NATURAL'S OPTION.
DURING THE INITIAL TERM, ANNUAL TOLL PAYMENTS BEFORE OPERATING COSTS WILL
BE APPROXIMATELY $35 MILLION.
(2) OFFSHORE EQUIPMENT OPERATING LEASES ARE PRIMARILY COMPRISED OF OBLIGATIONS
RELATED TO FPSOS. DURING 2006, CANADIAN NATURAL ENTERED INTO AN AGREEMENT
TO LEASE AN ADDITIONAL FPSO COMMENCING IN 2008, IN CONNECTION WITH THE
PLANNED OFFSHORE DEVELOPMENT IN GABON, OFFSHORE WEST AFRICA. THE NEW FPSO
LEASE AGREEMENT CONTAINS CANCELLATION PROVISIONS AT THE OPTION OF CANADIAN
NATURAL, SUBJECT TO ESCALATING TERMINATION PAYMENTS THROUGHOUT 2007 TO A
MAXIMUM OF US$395 MILLION.
(3) AMOUNTS REPRESENT MANAGEMENT'S ESTIMATE OF THE FUTURE UNDISCOUNTED
PAYMENTS TO SETTLE ASSET RETIREMENT OBLIGATIONS RELATED TO RESOURCE
PROPERTIES, FACILITIES, AND PRODUCTION PLATFORMS, BASED ON CURRENT
LEGISLATION AND INDUSTRY OPERATING PRACTICES. AMOUNTS DISCLOSED FOR THE
PERIOD 2007 - 2011 REPRESENT THE MINIMUM REQUIRED EXPENDITURES TO MEET
THESE OBLIGATIONS. ACTUAL EXPENDITURES IN ANY PARTICULAR YEAR MAY EXCEED
THESE MINIMUM AMOUNTS.
(4) THE LONG-TERM DEBT REPRESENTS PRINCIPAL REPAYMENTS ONLY. NO DEBT
REPAYMENTS ARE REFLECTED FOR $2,782 MILLION OF REVOLVING BANK CREDIT
FACILITIES DUE TO THE EXTENDABLE NATURE OF THE FACILITIES.
In 2005, the Board of Directors of Canadian Natural approved the construction
costs for Phase 1 of the Horizon Project, with an approved budget of $6.8
billion. Cumulative construction spending to December 31, 2006 was
approximately $4.0 billion. Final construction costs for Phase 1 may differ
from the approved budget due to changes in the final scope and timing of
completion of the project, and/or inflationary cost pressures.
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, 2006, 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
2
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
Canadian Natural 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.
3
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 28th day of March, 2007.
CANADIAN NATURAL RESOURCES LIMITED
By: /s/ Steve W. Laut
-----------------------------
Name: Steve W. Laut
Title: President and Chief
Operating Officer
4
Documents filed as part of this report:
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
1. Supplementary Oil & Gas Information for the fiscal year ended December
31, 2006.
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 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 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 GLJ Petroleum Consultants, independent petroleum engineering
consultants.