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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, 2008 Commission File Number: 333-146056
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CANADIAN NATURAL RESOURCES LIMITED
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(Exact name of Registrant as specified in its charter)
ALBERTA, CANADA
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(Province or other jurisdiction of incorporation or organization)
1311
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(Primary Standard Industrial Classification Code Numbers)
NOT APPLICABLE
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(I.R.S. Employer Identification Number (if
applicable))
2500, 855-2ND STREET S.W., CALGARY, ALBERTA, CANADA, T2P 4J8
TELEPHONE: (403) 517-7345
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(Address and telephone number of Registrant's principal executive offices)
CT CORPORATION SYSTEM, 111-8TH AVENUE, NEW YORK, NEW YORK 10011
(212) 894-8940
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(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.
540,991,318 COMMON SHARES OUTSTANDING AS OF DECEMBER 31, 2008
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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. 333-146056) under the Securities Act of 1933.
All dollar amounts in this Annual Report on Form 40-F are expressed in Canadian
dollars. As of March 26, 2009, the noon buying rate for Canadian Dollars as
expressed by the Bank of Canada was US$0.8110 equals C$ 1.00.
PRINCIPAL DOCUMENTS
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The following documents have been filed as part of this Annual Report on Form
40-F, starting on the following page:
A. ANNUAL INFORMATION FORM
Annual Information Form of Canadian Natural Resources Limited
("Canadian Natural") for the year ended December 31, 2008.
B. AUDITED ANNUAL FINANCIAL STATEMENTS
Canadian Natural's audited consolidated financial statements for the
years ended December 31, 2008 and 2007, including the auditor's report
with respect thereto. For a reconciliation of important differences
between Canadian and United States generally accepted accounting
principles, see Note 18 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, 2008.
SUPPLEMENTARY OIL & GAS INFORMATION
For Canadian Natural's Supplementary Oil & Gas Information for the year ended
December 31, 2008, see Exhibit 1 of this Annual Report on Form 40-F.
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[CANADIAN NATURAL RESOURCES LIMITED LOGO OMITTED]
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2008
MARCH 25, 2009
TABLE OF CONTENTS
DEFINITIONS....................................................................4
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS..............................6
RISK FACTORS...................................................................8
ENVIRONMENTAL MATTERS.........................................................11
REGULATORY MATTERS............................................................13
THE COMPANY...................................................................14
GENERAL DEVELOPMENT OF THE BUSINESS...........................................15
DESCRIPTION OF THE BUSINESS...................................................17
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES................18
Daily Production and Infrastructure..................................18
Developed and Undeveloped Acreage....................................19
Drilling Activity....................................................20
Producing Crude Oil and Natural Gas Wells............................23
Northeast British Columbia...........................................23
Northwest Alberta....................................................24
Northern Plains......................................................24
Southern Plains and Southeast Saskatchewan...........................26
Horizon Oil Sands Project............................................27
United Kingdom North Sea.............................................33
Offshore West Africa.................................................34
Cote d'Ivoire........................................................34
Gabon................................................................35
B. CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES....................36
C. RECONCILIATION OF CHANGES IN NET CONVENTIONAL RESERVES...................41
D. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION...............................42
E. NET CAPITAL EXPENDITURES.................................................47
F. DEVELOPED AND UNDEVELOPED ACREAGE........................................49
SELECTED FINANCIAL INFORMATION................................................49
CAPITAL STRUCTURE.............................................................50
MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES......................51
DIVIDEND HISTORY..............................................................52
TRANSFER AGENTS AND REGISTRAR.................................................52
DIRECTORS AND OFFICERS........................................................53
Canadian Natural Resources Limited 2
CONFLICTS OF INTEREST.........................................................58
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS....................58
AUDIT COMMITTEE INFORMATION...................................................59
LEGAL PROCEEDINGS.............................................................60
MATERIAL CONTRACTS............................................................60
INTERESTS OF EXPERTS..........................................................60
ADDITIONAL INFORMATION........................................................60
SCHEDULE "A" REPORT ON RESERVES DATA..........................................61
SCHEDULE "B" REPORT OF MANAGEMENT AND DIRECTORS...............................64
SCHEDULE "C" CHARTER OF THE AUDIT COMMITTEE...................................66
Canadian Natural Resources Limited 3
3 Canadian Natural Resources Limited
DEFINITIONS
The following are definitions of selected abbreviations used in this Annual
Information Form:
"API" means the specific gravity measured in degrees on the American Petroleum
Institute scale
"ARO" means Asset Retirement Obligation
"BBL" or "BARREL" means 34.972 Imperial gallons or 42 US gallons
"BCF" means one billion cubic feet
"BBL/D" means barrels per day
"BOE" means barrel of oil equivalent
"BOE/D" means barrel of oil equivalent per day
"CO2" means carbon dioxide
"CO2E" means carbon dioxide equivalents
"CANADIAN GAAP" means Generally Accepted Accounting Principles in Canada
"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 coal bed methane
"CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS" includes all of the Company's
light/medium, primary heavy, and thermal heavy crude oil, natural gas, coal bed
methane and NGLs reserves. It does not include the Company's oil sands mining
reserves
"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 unproved 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
Canadian Natural Resources Limited 4
"MMCF" means one million cubic feet
"MMCF/D" means one million cubic feet per day
"NGLS" means natural gas liquids
"NET ACRES" refers to gross acres multiplied by the percentage working interest
therein owned or to be owned by the Company
"NET ASSET VALUE" means the discounted value of conventional crude oil and
natural gas reserves plus the value of undeveloped land, less net debt
"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
"SCO" means synthetic light crude oil
"SEC" means United States Securities and Exchange Commission
"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
"UK" means the United Kingdom
"US" means United States
"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 Canadian Natural Resources Limited
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents incorporated herein by
reference constitute forward-looking statements or information (collectively
referred to herein as "forward-looking statements") within the meaning of
applicable securities legislation. Forward-looking statements can be identified
by the words "believe", "anticipate", "expect", "plan", "estimate", "target",
"continue", "could" "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook", "effort"
"seeks", "schedule" or expressions of a similar nature suggesting future
outcome or statements regarding an outlook. Disclosure related to expected
future commodity pricing, production volumes, royalties, operating costs,
capital expenditures, and other guidance provided throughout this document
constitute forward looking statements. Disclosure of plans relating to existing
and future developments, including but not limited to the Horizon Project,
Primrose East, Pelican Lake, Gabon Offshore West Africa, and the Kirby Oil
Sands Project also constitute forward-looking statements. This forward-looking
information is based on annual budgets and multi-year forecasts, and is
reviewed and revised throughout the year if necessary in the context of
targeted financial ratios, project returns, product pricing expectations and
balance in project risk and time horizons. These statements are not guarantees
of future performance and are subject to certain risks and the reader should
not place undue reliance on these forward looking statements as there can be no
assurances that the plans, initiatives or expectations upon which they are
based will occur.
In addition, statements relating to "reserves" are deemed to be forward-looking
statements as they involve the implied assessment based on certain estimates
and assumptions that the reserves described can be profitably produced in the
future. There are numerous uncertainties inherent in estimating quantities of
proved crude oil and natural gas reserves and in projecting future rates of
production and the timing of development expenditures. The total amount or
timing of actual future production may vary significantly from reserve and
production estimates.
The forward-looking statements are based on current expectations, estimates and
projections about the Company and the industry in which the Company operates,
which speak only as of the date such statements were made or as of the date of
the report or document in which they are contained and are subject to known and
unknown risks, uncertainties and other factors that could cause the actual
results, performance or achievements of the Company 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; volatility of and assumptions
regarding crude oil and natural gas prices; fluctuations in currency and
interest rates; assumptions on which the Company's current guidance is based;
economic conditions in the countries and regions in which the Company conducts
business; political uncertainty, including actions of or against terrorists,
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 Company's
defense of lawsuits; availability and cost of seismic, drilling and other
equipment; ability of the Company and its subsidiaries to complete its capital
programs; the Company's and its subsidiaries' ability to secure adequate
transportation for its products; unexpected difficulties in mining, extracting
or upgrading the Company's bitumen products; potential delays or changes in
plans with respect to exploration or development projects or capital
expenditures; ability of the Company to attract the necessary labour required
to build its thermal and oil sands mining 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; the Company's and its
subsidiaries' success of exploration and development activities and their
ability to replace and expand crude oil and natural gas reserves; timing and
success of integrating the business and operations of acquired companies;
production levels; imprecision of reserve estimates and estimates of
recoverable quantities of crude oil, bitumen, natural gas and liquids not
currently classified as proved; actions by governmental authorities; government
regulations and the expenditures required to comply with them (especially
safety and environmental laws and regulations and the impact of climate change
initiatives on capital and operating costs); asset retirement obligations; the
adequacy of the Company's provision for taxes; and other circumstances
affecting revenues and expenses. Certain of these factors are discussed in more
detail under the heading "Risk Factors". The Company's operations have been,
and at times in the future may be affected by political developments and by
federal, provincial and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate controls and
environmental protection regulations. Should one or more of these risks or
uncertainties materialize, or should any of the Company's assumptions prove
incorrect, actual results may vary in material respects from those projected in
the forward-looking statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as such factors
are dependent upon other factors, and the Company's course of action would
depend upon its assessment of the future considering all information then
available.
Readers are cautioned that the foregoing list of important factors is not
exhaustive. Unpredictable or unknown factors not discussed in this report could
also have material adverse effects on forward-looking statements. Although the
Company believes that the expectations conveyed by the forward-looking
statements are reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or persons
acting on its behalf are expressly qualified in their entirety by these
cautionary statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements should circumstances or
Management's estimates or opinions change.
Canadian Natural Resources Limited 6
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,
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, 2008, the Company retained a qualified
independent reserves evaluator, Sproule Associates Limited ("Sproule"), to
evaluate 100% of the Company's conventional proved, as well as proved and
probable crude oil, NGLs and natural gas reserves and prepare Evaluation
Reports on these reserves. Conventional crude oil, NGLs and natural gas
reserves include all of the Company's light/medium, primary heavy, and thermal
heavy crude oil, natural gas, coal bed methane and NGLs reserves. They do not
include the Company's oil sands mining reserves. The Company has been granted
an exemption from certain of the provisions of 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 three principal differences between the two standards. The
first is 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. 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 third is the requirement to disclose a gross
reserve reconciliation (before the consideration of royalties). The Company
discloses its conventional crude oil, NGLs, and natural gas reserve
reconciliations net of royalties in adherence to SEC requirements.
For the year ended December 31, 2008, 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 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 proved and probable crude
oil, NGLs and natural gas reserves.
The Company annually discloses 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 and in its
annual Form 40-F filing with the SEC. 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. 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 additional voluntary
information, which is disclosed in this Annual Information Form.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with both Sproule 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 Canadian Natural Resources Limited
SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES
This Annual Information Form 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 non-GAAP measures adjusted net earnings from operations and cash flow from
operations are reconciled to net earnings, as determined in accordance with
Canadian GAAP in the "Financial Highlights" section the Company's MD&A which is
incorporated by reference into this document.
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. Significant
declines 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, industrial demand,
prices of alternate sources of energy, and the import of liquefied natural gas.
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, including but not limited to the Horizon
Project, Primrose East, Pelican Lake, Gabon Offshore West Africa, and the Kirby
Oil Sands Project, or curtailment in production at some properties or result in
unutilized long-term transportation commitments, all of which could have a
material adverse effect on Canadian Natural's revenues, net earnings 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 forecast
prices decline, the carrying value of property, plant and equipment could be
subject to downward revisions, and net earnings could be adversely affected.
Approximately 28% of the Company's 2008 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 quality difference and the mix of product obtained in the
refining process referred to as the "quality differential". 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 quality differentials are
uncertain and a significant increase in the heavy crude oil differentials could
have a material adverse effect on the Company's business.
NEED TO REPLACE RESERVES
Canadian Natural's future crude oil and natural gas reserves and production,
and therefore its cash flows and results of operations, are highly dependent
upon success in exploiting its current reserve base and acquiring or
discovering additional reserves. Without additions to reserves through
exploration, acquisition or development activities, the Company's production
will decline over time as reserves are depleted. The business of exploring for,
developing or acquiring reserves is capital intensive. To the extent the
Company's cash flows from operations are insufficient to fund capital
expenditures and external sources of capital become limited or unavailable, the
Company's ability to make the necessary capital investments to maintain and
expand its crude oil and natural gas reserves will be impaired. In addition,
Canadian Natural may be unable to find and develop or acquire additional
reserves to replace its crude oil and natural gas production at acceptable
costs.
Canadian Natural Resources Limited 8
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,
royalties, 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.
COMPLETION RISK
Canadian Natural has a variety of exploration, development and construction
projects underway at any given time. Project delays may result in delayed
revenue receipts and cost overruns may result in projects being uneconomic. The
Company's ability to complete projects is dependent on general business and
market conditions as well as other factors beyond our control including the
availability of skilled labour and manpower, the availability and proximity of
pipeline capacity, weather, environmental and regulatory matters, ability to
access lands, availability of drilling and other equipment, and availability of
processing capacity.
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 related 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
include integrated oil and natural gas companies and numerous other senior oil
and natural gas companies, some of which may have financial and other resources
greater than the Company.
ACCESS TO SOURCES OF LIQUIDITY
The ongoing worldwide financial and economic events have resulted in a
significant tightening of the availability and cost of new sources of
liquidity, including bank credit facilities and funds derived from debt capital
markets. The ability of the Company to fund current and future capital projects
and carry out our business plan is dependent on our ability to raise capital in
a timely manner under favourable terms and conditions.
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.
9 Canadian Natural Resources Limited
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. Increasingly stringent laws and regulations, including any new
regulations the US may impose to limit purchases of crude oil towards less
energy intensive sources, may have an adverse effect on the Company's future
net earnings and cash flow from operations.
GREENHOUSE GAS AND OTHER AIR EMISSIONS
There are a number of unresolved issues in relation to Canadian federal and
provincial GHG regulatory requirements. Key among them is an appropriate common
facility emissions threshold, availability and duration of compliance
mechanisms and resolution of federal/provincial harmonization agreements. The
Company continues to pursue GHG emissions reduction initiatives including
solution gas conservation, CO2 capture and sequestration in oil sands tailings,
CO2 capture and storage in association with enhanced oil recovery and
participation in an industry initiative to promote an integrated CO2 capture
and storage network.
Air pollutant standards and guidelines are being developed federally and
provincially and the Company is participating in these discussions. Ambient air
quality and sector based reductions in air emissions are being reviewed.
Through participation of the Company and the industry with stakeholders,
guidelines have been developed that adopt a structured process to emissions
reductions that is commensurate with technological development and operational
requirements.
In Canada, the Federal government has indicated its intent to develop
regulations that would be in effect in 2010 to address industrial GHG
emissions; however future Federal regulatory requirements currently remain
uncertain. The Federal Government has also outlined national and sectoral
reduction targets for several categories of air pollutants. In Alberta, GHG
regulations came into effect July 1, 2007, affecting facilities emitting more
than 100 kilotonnes of CO2e annually. Two Canadian Natural facilities, the
Primrose/Wolf Lake in-situ heavy oil crude oil facilities and the Hays sour
natural gas plant, fall under the regulations. In British Columbia, a $10/tonne
carbon tax was implemented July 1, 2008, applying to combustion of all fossil
fuels, increasing to $30/tonne by July 2012. In the UK, greenhouse gas
regulations have been in effect since 2005. During Phase 1 (2005-2007) of the
UK National Allocation Plan the Company operated below its CO2 allocation. For
Phase 2 (2008-2012) the Company's CO2 allocation has been decreased below the
Company's estimated current operations emissions. The compliance costs to the
Company relating to the above regulations for 2008 are approximately $24
million.
The additional requirements of enacted or proposed GHG legislation on the
Company's operations will 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.
HEDGING ACTIVITIES
In response to fluctuations in commodity prices, foreign exchange, and interest
rates, the Company may utilize various derivative financial instruments and
physical sales contracts to manage its exposure under a defined hedging
program. The terms of these arrangements may limit the benefit to the Company
of favourable changes in these factors and may result in financial or
opportunity loss due to paying royalties on a reference price which is higher
than the hedged price and counterparty credit risk.
OPERATIONAL RISK
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 and maintains a
comprehensive insurance program, however, Canadian Natural's liability,
property and business interruption insurance may not and possibly will not
provide adequate coverage in all circumstances.
Canadian Natural Resources Limited 10
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
Canada or the United States.
Canadian Natural's arrangement for the exploration and development of crude oil
and natural gas properties in Canada and the UK sector of the North Sea differs
distinctly from its arrangement for the exploration and development in other
foreign crude oil and natural gas properties. In some foreign countries in
which the Company does and may do business in the future, the state generally
retains ownership of the minerals and consequently retains control of, and in
many cases participates in, the exploration and production of reserves.
Accordingly, operations 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.
OTHER BUSINESS RISKS
Other business risks relate to the dependency on third party operators for some
of the Company's assets, timing and success of integrating the business and
operations of acquired companies, credit risk related to non-payment for sales
contracts or non-performance by counterparties to contracts, risk of
litigation, regulatory issues, and risk of increases in government taxes and
changes to the royalty regime. The majority of the Company's assets are held in
one or more corporate subsidiaries or partnerships. The results of operations
and ability to service indebtedness, including debt securities, are dependent
upon the results of operations of these subsidiaries and partnerships and, in
the case of subsidiaries, the payment of funds 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 subsidiary or
partnership, 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.
ENVIRONMENTAL MATTERS
The Company carries out its activities in compliance with all relevant
regional, national and international regulations and industry standards.
Environmental specialists in Canada and the UK 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. 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 internal environmental compliance audit and inspection
program of its operating facilities; a 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; a due diligence program related to
groundwater monitoring; an active program related to preventing spills and
reclaiming spill sites; a solution gas reduction and conservation program; a
program to replace the majority of fresh water for steaming with brackish
water; environmental planning for all projects to assess environmental impacts
and to implement avoidance, and mitigation programs; reporting for
environmental liabilities; a program to optimize efficiencies at the Company's
operating facilities; and continued evaluation of new technologies to reduce
11 Canadian Natural Resources Limited
environmental impacts. The Company has also established stringent operating
standards in four areas: implementing cost effective ways of reducing GHG per
unit of production; exercising care with respect to all waste produced through
effective waste management plans; using water-based, environmentally friendly
drilling muds whenever possible; and minimizing produced water volumes onshore
and offshore through cost-effective measures. Canadian Natural participates in
both the Canadian federal and provincial regulated GHG emissions programs. 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 the Companies overall
goal of a net reduction of GHG emissions per unit of production.
The Company is concurrently participating with certain industry groups who in
turn are working with legislators and regulators to develop and implement new
GHG emissions laws and regulations. Internally, the Company is pursuing an
integrated emissions reduction strategy. The Company continues to develop
strategies that will enable it to deal with the risks and opportunities
associated with new GHG and air emissions 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 remains focused on implementing reduction programs based on
efficiency audits of its major facilities to reduce CO2 emissions and on
trading mechanisms to ensure compliance with any requirement now in effect.
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 the
Company's environmental work plan and are operated within all regulatory
standards and guidelines. The Company 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 2008 the Company completed approximately 101 gas
conservation projects, resulting in a reduction of 835,000 tonnes/year of CO2e.
Over the past five years the Company has spent over $89 million to conserve the
equivalent of over 6.3 million tonnes of CO2e. The Company also monitors the
performance of its compressor fleet which is continually modified and optimized
for maximum efficiency. These programs also influence and direct the Company's
plans for new projects and facilities. The Horizon Project has incorporated
advancements in technology to further reduce 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 CO2 capture and
the sequestration of CO2 in oils sands tailings.
In its North Sea operations the Company continues to focus on implementing
reduction programs based on efficiency audits of its major facilities. Projects
to reduce GHG emissions included a flare recovery pilot study, change out of
flare purge valves and introduction of water washing on turbines. The Produced
Water Re-injection on Ninian Central was made permanent in 2008 during which
time approximately 1.36 million cubic meters of produced water were re-injected
to the reservoir. This resulted in approximately 18 tonnes of oil in produced
water not being discharged to sea, a reduction of approximately 6%.
For 2008, the Company's capital expenditures included $38 million for
abandonment expenditures (2007 - $71 million).
The Company's estimated undiscounted ARO at December 31, 2008 was as follows:
-----------
Estimated ARO, undiscounted ($millions) | 2008 | 2007
-----------------------------------------------------------|----------|---------
North America | $ 3,165 | $ 3,038
North Sea | 1,216 | 1,286
Offshore West Africa | 93 | 102
-----------------------------------------------------------|----------|---------
| 4,474 | 4,426
North Sea PRT recovery | (529) | (555)
-----------------------------------------------------------|----------|---------
| $ 3,945 | $ 3,871
===========================================================|==========|=========
The estimate of 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
estimated to result in a PRT recovery of $529 million (2007 - $555 million), as
abandonment costs are an allowable deduction in determining PRT and may be
Canadian Natural Resources Limited 12
carried back to reclaim PRT previously paid. The expected PRT recovery reduces
the Company's net undiscounted abandonment liability to $3,945 million (2007 -
$3,871 million).
REGULATORY MATTERS
The Company's business is subject to regulations generally established by
government legislation and governmental agencies. The regulations are
summarized in the following paragraphs.
CANADA
The petroleum and natural gas industry in Canada operates under government
legislation and regulations, which govern exploration, development, production,
refining, marketing, transportation, 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 are
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 Alberta oil sands permit and oil sands primary lease is issued for five and
fifteen years respectively. If the minimum level of evaluation of an oil sands
permit is attained, a primary oil sands lease will be issued out of the permit.
A primary oil sands lease is continued based on the minimum level of evaluation
attained on such lease. Continued primary oil sands leases that are designated
as "producing" will continue for their productive lives while those designated
as "non-producing" can be continued by payment of escalating rentals.
The provincial governments regulate the production of crude oil and natural gas
as well as the removal of natural gas and NGLs from each province. Government
royalties are payable on crude oil, NGLs 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.
The Alberta Government implemented its New Royalty Framework (NRF) effective
January 1, 2009. The NRF includes a number of changes to royalty rates for
natural gas, conventional crude oil, and oil sands production. Under the NRF,
royalties payable are variable according to commodity prices and the
productivity of wells.
The NRF for conventional crude oil and natural gas operates based on sliding
scales ranging up to 50% determined by commodity prices and well productivity.
Government royalties on a significant portion of Alberta crude oil production
fall under the oil sands royalty regime and are calculated on a project by
project basis as a percentage of gross revenue less operating, capital and
abandonment costs ("net profit"). For 2008 and prior years, royalties were
calculated as 1% of gross revenues until the Company's capital investment in
the applicable project were fully recovered, at which time the royalty
increased to 25% of net profit. Effective January 1, 2009 the NRF includes the
implementation of a sliding scale for oil sands royalties ranging from 1% to 9%
on a gross revenue basis pre-payout and 25% to 40% on a net revenue basis
post-payout depending on benchmark crude oil pricing.
In addition to government royalties, the Company is currently subject to
federal and provincial income taxes in Canada at a combined rate of
approximately 29% after allowable deductions.
During 2007, the Canadian Federal Government enacted income tax rate changes
which decrease the Federal corporate income tax rate over a five year period
from 21% in 2007, 19.5% in 2008, 19% in 2009, to 15% in 2012.
13 Canadian Natural Resources Limited
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% charged on crude
oil and natural gas profits. Approvals granted on or after March 16, 1993 are
exempted from PRT and government royalties. Profits for PRT purposes are
calculated on a field-by-field basis by deducting field operating costs and
field development costs from production and third-party tariff revenue. In
addition, certain statutory allowances are available, which may reduce the PRT
payable. There is no PRT on profits of decommissioned fields subsequently
redeveloped, subject to certain conditions being met.
The Company is subject to UK Corporation Tax ("CT") on its UK profits at a
current rate of 30%. PRT paid is deductible for CT purposes. An additional
Supplementary Charge Tax ("SCT") of 20% is charged on crude oil and natural gas
profits but excludes any deduction for financing costs. The deduction for crude
oil and natural gas expenditures on capital items is generally 100% in the year
incurred.
OFFSHORE WEST AFRICA
Terms of licences, including royalties and taxes payable on production or
profit sharing arrangements, vary by country and, in some cases, by concession
within each country.
Development of the Espoir Field in Block CI-26 and the Baobab Field in Block
CI-40, offshore Cote d'Ivoire, are subject to Production Sharing Agreements
("PSA") that deem tax or royalty payments to the Government are met from the
Government's share of profit oil. The current Corporate Income Tax rate in Cote
d'Ivoire is 25% which is applicable to non PSA income.
The Olowi Field offshore Gabon is also under the terms of a PSA which deems tax
or royalty payments to the Government are met from the Government's share of
profit oil. The current Corporate Income Tax rate is 35% which is applicable to
non PSA income.
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 November 2, 2006, pursuant to a Purchase and Sale Agreement, the Company
acquired all of the outstanding shares of Anadarko Canada Corporation, a
subsidiary of Anadarko Petroleum Corporation. 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. On January 1,
2007, ACC-CNR Resources Corporation and the Company amalgamated pursuant to the
BUSINESS CORPORATIONS ACT (Alberta) under the name Canadian Natural Resources
Limited.
Canadian Natural Resources Limited 14
On January 1, 2008 Ranger Oil (International) Ltd., 764968 Alberta Inc., CNR
International (Norway) Limited, Renata Resources Inc. and the Company
amalgamated pursuant to the BUSINESS CORPORATIONS ACT (Alberta) under the name
Canadian Natural Resources Limited.
The main operating subsidiaries and partnerships of the Company, percentage of
voting securities owned either directly or indirectly, and their jurisdictions
of incorporation are as follows:
SUBSIDIARY JURISDICTION OF INCORPORATION % OWNERSHIP
---------- ----------------------------- -----------
CanNat Energy Inc. Delaware 100
CNR (ECHO) Resources Inc. Alberta 100
CNR International (U. K.) Investments Limited England 100
CNR International (U. K.) Limited England 100
CNR International Cote d'Ivoire SARL Cote d'Ivoire 100
CNR International (Olowi) Limited Bahamas 100
CNR Petro Resources Limited Alberta 100
Horizon Construction Management Ltd. Alberta 100
PARTNERSHIP
Canadian Natural Resources Partnership Alberta 100
Canadian Natural Resources Northern Alberta Partnership Alberta 100
CNR 2006 Partnership Alberta 100
In the ordinary course of business, Canadian Natural restructures its
subsidiaries and partnerships to maintain efficient operations and to
facilitate acquisitions and divestitures.
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 - THREE YEAR HISTORY
2006
In January 2006 the Company issued $400 million of 4.50% unsecured notes
maturing January 23, 2013 pursuant to a short form Canadian base shelf
prospectus dated August 29, 2005.
On August 17, 2006, the Company issued US$250 million of 10 year 6.0% unsecured
notes maturing August 15, 2016 and US$450 million of 30 year 6.50% unsecured
notes maturing February 15, 2037 pursuant to a US 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. At the time, the assets produced 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 included 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. In March 2007, $1,500 million of the
credit facility was repaid reducing the facility to $2,350 million. In February
2009, $420 million of the credit facility was repaid reducing the facility to
$1,930 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. 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.
15 Canadian Natural Resources Limited
2007
On March 19, 2007, the Company issued US$1,100 million of 10 year 5.70%
unsecured notes maturing May 15, 2017 and US$1,100 million of 30 year 6.25%
unsecured notes maturing March 15, 2038 pursuant to a US short form base shelf
prospectus dated November 27, 2006.
On December 18, 2007 the Company issued $400 million of 3 year 5.50% unsecured
notes maturing December 17, 2010 pursuant to a Canadian short form base shelf
prospectus dated September 25, 2007.
During 2007, the Company completed 67 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties. The
aggregate net expenditure of the transactions was $70.9 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 33 transactions to dispose of
non-core operated and non-operated properties for proceeds of $109.9 million.
2008
On January 17, 2008, the Company issued US$400 million of 5 year 5.15%
unsecured notes maturing February 1, 2013, US$400 million of 10 year 5.90%
unsecured notes maturing February 1, 2018 and US$400 million of 31 year 6.75%
unsecured notes maturing February 1, 2039 pursuant to a US short form base
shelf prospectus dated September 25, 2007.
In the third quarter of 2008, the Company committed 120,000 bbl/d to the
Keystone Pipeline US Gulf Coast Expansion for a 20 year period, subject to
regulatory approval. Concurrently the Company entered into a 20 year supply
agreement with a major US refiner for 100,000 bbl/d of heavy crude oil to US
Gulf Coast refineries, contingent on the completion of the Keystone Pipeline US
Gulf Coast Expansion.
The Company entered into an agreement in August 2005 to obtain pipeline
transportation service for the Horizon Project. The initial term of the
agreement is 25 years, which commenced on the in-service date of November 1,
2008. The twinning of the existing Alberta Oil Sands Pipeline ("AOSPL"),
resulting in two parallel pipelines, one of which is dedicated to Canadian
Natural, combined with the 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. In addition
to having the option to renew the agreement for successive 10 year terms, the
Company has the right to request incremental expansion of the Horizon Pipeline
based upon applicable National Energy Board approved multi pipeline economics.
This agreement allows the Company to gain access to major sales pipelines out
of Edmonton for the Company's synthetic crude oil transportation service for
the Horizon Project, while at the same time providing significant quality
benefits associated with being the only shipper on the Horizon Pipeline.
During 2008, the Company completed 55 transactions in the normal course to
acquire additional interests in crude oil and natural gas properties. The
aggregate net expenditure of the transactions was $381 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 33 transactions to dispose of
non-core operated and non-operated properties for proceeds of $45 million.
2009
First synthetic crude oil production was achieved at the Horizon Project on
February 28, 2009. First shipment into the Horizon Pipeline occurred on March
18, 2009. Capital expenditures are expected to be $621 million in 2009 for
remaining Phase 1 construction, commissioning and inventory costs, as wells as
sustaining capital costs and Tranche 2 expansion.
For 2009, the Company's overall conventional drilling activity in North America
is expected to comprise approximately 142 natural gas wells and 465 crude oil
wells, excluding stratigraphic and service wells. The company has reduced 2009
natural gas drilling in Alberta due to the anticipated future impact of royalty
changes arising under the NRF which became effective January 1, 2009 and the
current low prices received for natural gas. Forecasted conventional capital
expenditures in North America for 2009 are currently expected to be
approximately $1.7 billion, excluding property acquisitions and dispositions.
The Company's drilling activity in 2009 for the North Sea is expected to be 0.9
net platform wells with focus on building drilling and workover inventory for
2010. Capital expenditures are expected to be $141 million.
In Offshore West Africa, capital expenditures are expected to be $553 million
in 2009, including $80 million to complete Phase 2 development of the Baobab
Field in Cote d'Ivoire, where the Company is currently drilling the fourth and
final well which is expected to be completed in the second quarter of 2009.
Canadian Natural Resources Limited 16
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 initiates, operates and maintains a large working interest in a
majority of the prospects in which it participates. Canadian Natural's
objectives are to increase crude oil and natural gas production, reserves, cash
flow and net asset value on a per common share basis through the development of
its existing crude oil and natural gas properties and through the discovery
and/or acquisition of new reserves.
The Company has a full complement of management, technical and support staff to
pursue these objectives. As at December 31, 2008 the Company had 3,782
permanent employees in North America and 350 permanent employees in its
international operations. Included in the North American numbers are the
Horizon Project team, consisting of 1,245 permanent employees.
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, light/medium crude oil and NGLs, Pelican Lake crude oil (14-17(0)
API oil, which receives medium quality crude netbacks due to lower production
costs and lower royalty rates), 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 44% of 2008 production. Virtually all of the Company's natural gas and NGLs
production is located in the Canadian provinces of Alberta, British Columbia
and Saskatchewan and is marketed in Canada and the United States. Light/medium
crude oil and NGLs, representing 22% of 2008 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 28% of 2008 production. Other heavy crude oil, which
accounts for 6% of 2008 production, is produced from the Pelican Lake area in
north Alberta. This production is developed through a staged horizontal
drilling program complimented by water and polymer flooding. Midstream assets,
comprised of three crude oil pipelines and an electricity co-generation
facility, provide cost effective infrastructure supporting the primary and
thermal heavy and Pelican Lake crude oil operations.
With approximately 12.1 million net acres of core undeveloped land base, the
Company believes it has sufficient project portfolios in each of the product
offerings to provide growth for the next several years.
17 Canadian Natural Resources Limited
A. PRINCIPAL CRUDE OIL, NATURAL GAS AND OIL SANDS PROPERTIES
DAILY PRODUCTION AND INFRASTRUCTURE
Set forth below is a summary of the conventional crude oil, NGLs and natural
gas properties as at December 31, 2008. The information reflects the working
interests owned by the Company. FPSO's, included under major infrastructure,
are leased by the Company under varying terms.
2008 Average Daily 2007 Average Daily Major Infrastructure
Production Rates Production Rates As at Dec 31, 2008
---------------------------------------------------------------------------------------------------------------------------------
Region Batteries/
Crude oil & Crude oil Compressors & Plants/
NGLs Natural gas & NGLs Natural gas Platforms/
(mbbl) (mmcf) (mbbl) (mmcf) FPSO
---------------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Northeast British Columbia 5.9 377 7.0 430 1/10/-/-
Northwest Alberta 16.4 531 17.0 596 -/13/-/-
Northern Plains 200.7 382 201.4 418 11/9/-/-
Southern Plains 12.2 177 12.7 196 -/3/-/-
Southeast Saskatchewan 8.4 3 8.4 2 -/-/-/-
Non-core regions 0.2 2 0.3 1 -/-/-/-
---------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
North Sea UK Sector 45.3 10 55.9 13 -/-/5/1
Offshore West Africa
Cote d'Ivoire 26.6 13 28.5 12 -/-/-/2
Gabon - - - - -/-/-/-
Non-core regions
South Africa - - - - -/-/-/-
---------------------------------------------------------------------------------------------------------------------------------
TOTAL 315.7 1,495 331.2 1,668 12/35/5/3
=================================================================================================================================
Canadian Natural Resources Limited 18
DEVELOPED AND UNDEVELOPED ACREAGE
The following table summarizes the Companies landholdings as at December 31,
2008.
Average Working
Developed Acreage Undeveloped Acreage Total Acreage Interest
-----------------------------------------------------------------------------------------------------------------------------------
Region (thousands of acres) Gross Net Gross Net Gross Net %
-----------------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Northeast British
Columbia 1,478 1,107 3,037 2,227 4,515 3,334 74
Northwest Alberta 1,205 859 1,808 1,352 3,013 2,211 73
Northern Plains 4,126 3,326 7,354 6,452 11,480 9,778 85
Southern Plains 1,603 1,251 975 832 2,578 2,083 81
Southeast Saskatchewan 89 73 146 130 235 203 87
In-Situ Oil Sands 23 23 598 495 621 518 84
Horizon Oil Sands - - 115 115 115 115 100
Non-core regions 23 8 1,276 179 1,299 187 14
-----------------------------------------------------------------------------------------------------------------------------------
INTERNATIONAL
North Sea UK Sector 108 74 314 258 422 332 79
Offshore West Africa
Cote d'Ivoire 7 4 95 55 102 59 58
Gabon - - 152 137 152 137 90
Non-core regions
South Africa - - 4,002 4,002 4,002 4,002 100
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 8,662 6,725 19,872 16,234 28,534 22,959 80
===================================================================================================================================
19 Canadian Natural Resources Limited
DRILLING ACTIVITY
Set forth below is a summary of conventional crude oil, NGLs and natural gas
drilling activity of the Company for the fiscal year ending December 31, 2008
by geographic region:
2008
----------------------------------------------------------------------------|-----------------------------------------------------
Exploration | Development
----------------------------------------------------------------------------|-----------------------------------------------------
Crude Natural Dry Service/ Total |Crude Natural Dry Service/ Total
Oil Gas Stratigraphic | Oil Gas Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH AMERICA |
Northeast |
British Columbia Gross - 2.0 2.0 - 4.0 | - 26.0 4.0 - 30.0
Net - 1.5 1.5 - 3.0 | - 22.5 1.9 - 24.4
Northwest Alberta Gross 1.0 14.0 1.0 - 16.0 | 14.0 62.0 3.0 3.0 82.0
Net 0.6 12.6 0.9 - 14.1 | 8.9 54.0 2.6 2.2 67.7
Northern Plains Gross 27.0 14.0 5.0 - 46.0 | 583.0 131.0 22.0 33.0 769.0
Net 26.3 11.4 5.0 - 42.7 | 557.3 88.4 21.5 32.4 699.6
Southern Plains Gross 4.0 6.0 1.0 - 11.0 | 29.0 153.0 1.0 - 183.0
Net 4.0 6.0 1.0 - 11.0 | 26.9 72.8 1.0 - 100.7
Southeast |
Saskatchewan Gross 6.0 - 2.0 - 8.0 | 57.0 - - 2.0 59.0
Net 4.6 - 2.0 - 6.6 | 48.9 - - 1.7 50.6
Non-core Regions Gross - - - - - | - 3.0 2.0 - 5.0
Net - - - - - | - 0.1 0.4 - 0.5
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA |
UK SECTOR Gross 1.0 - - - 1.0 | 2.0 - 1.0 1.0 4.0
Net 0.8 - - - 0.8 | 1.6 - 0.8 0.9 3.3
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE Gross - - - - - | 4.0 - - 2.0 6.0
WEST AFRICA |
Net - - - - - | 2.3 - - 1.8 4.1
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL GROSS 39.0 36.0 11.0 - 86.0 | 689.0 375.0 33.0 41.0 1,138.0
NET 36.3 31.5 10.4 - 78.2 | 645.9 237.8 28.2 39.0 950.9
============================================================================|=====================================================
Total success rate excluding service and stratigraphic test wells for 2008 is
96% (2007 - 91%, 2006 - 91%)
Canadian Natural Resources Limited 20
2007
----------------------------------------------------------------------------|-----------------------------------------------------
Exploration | Development
----------------------------------------------------------------------------|-----------------------------------------------------
Crude Natural Dry Service/ Total |Crude Natural Dry Service/ Total
Oil Gas Stratigraphic | Oil Gas Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH AMERICA |
Northeast British |
Columbia Gross - 7.0 7.0 - 14.0| 3.0 45.0 12.0 - 60.0
Net - 7.0 6.0 - 13.0| 2.9 35.1 10.1 - 48.1
Northwest Alberta Gross 1.0 23.0 5.0 - 29.0| 21.0 102.0 14.0 2.0 139.0
Net 1.0 16.4 3.8 - 21.2| 12.1 82.1 8.9 1.5 104.6
Northern Plains Gross 26.0 31.0 20.0 97.0 174.0| 545.0 82.0 44.0 49.0 720.0
Net 23.8 24.7 19.4 97.0 164.9| 500.6 70.9 42.4 48.8 662.7
Southern Plains Gross 1.0 14.0 1.0 - 16.0| 19.0 174.0 2.0 1.0 196.0
Net 1.0 13.4 1.0 - 15.4| 18.1 134.1 0.6 1.0 153.8
Southeast |
Saskatchewan Gross 1.0 - - - 1.0| 27.0 - 2.0 4.0 33.0
Net 1.0 - - - 1.0| 23.0 - 0.4 4.0 27.4
Non-core Regions Gross - - - - -| - - - - -
Net - - - - -| - - - - -
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA |
UK SECTOR Gross - - - - -| 4.0 - - 4.0 8.0
Net - - - - -| 3.7 - - 3.5 7.2
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE Gross - - - - -| 7.0 - - 1.0 8.0
WEST AFRICA |
Net - - - - -| 4.1 - - 0.6 4.7
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL Gross 29.0 75.0 33.0 97.0 234.0| 626.0 403.0 74.0 61.0 1,164.0
Net 26.8 61.5 30.2 97.0 215.5| 564.5 322.2 62.4 59.4 1,008.5
============================================================================|=====================================================
21 Canadian Natural Resources Limited
2006
----------------------------------------------------------------------------|-----------------------------------------------------
Exploration | Development
----------------------------------------------------------------------------|-----------------------------------------------------
Crude Natural Dry Service/ Total |Crude Natural Dry Service/ Total
Oil Gas Stratigraphic | Oil Gas Stratigraphic
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH AMERICA |
Northeast British |
Columbia Gross 2.0 19.0 6.0 - 27.0| 12.0 166.0 15.0 - 193.0
Net 2.0 15.1 5.6 - 22.7| 10.9 148.0 14.1 - 173.0
Northwest Alberta Gross 2.0 22.0 10.0 - 34.0| 19.0 165.0 19.0 - 203.0
Net 2.0 15.7 9.5 - 27.2| 12.5 137.1 14.6 - 164.2
Northern Plains Gross 18.0 110.0 31.0 129.0 288.0| 504.0 175.0 40.0 78.0 797.0
Net 13.6 90.6 28.2 128.9 261.3| 470.4 128.1 36.1 78.0 712.6
Southern Plains Gross 2.0 34.0 9.0 - 45.0| 6.0 154.0 1.0 - 161.0
Net 2.0 29.8 8.4 - 40.2| 4.2 74.4 1.0 - 79.6
Southeast |
Saskatchewan Gross - - - - -| 84.0 - 2.0 - 86.0
Net - - - - -| 72.7 - 2.0 - 74.7
Non-core Regions Gross - 2.0 - - 2.0| 2.0 8.0 - 1.0 11.0
Net - 0.6 - - 0.6| 0.5 2.2 - 1.0 3.7
----------------------------------------------------------------------------|-----------------------------------------------------
NORTH SEA |
UK SECTOR Gross - - - - -| 8.0 - - 2.0 10.0
Net - - - - -| 7.4 - - 1.8 9.2
----------------------------------------------------------------------------|-----------------------------------------------------
OFFSHORE Gross - - - - -| 7.0 - - 3.0 10.0
WEST AFRICA |
Net - - - - -| 4.1 - - 1.7 5.8
----------------------------------------------------------------------------|-----------------------------------------------------
TOTAL Gross 24.0 187.0 56.0 129.0 396.0| 642.0 668.0 77.0 84.0 1,471.0
Net 19.6 151.8 51.7 128.9 352.0| 582.7 489.8 67.8 82.5 1,222.8
============================================================================|=====================================================
Canadian Natural Resources Limited 22
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, 2008:
Natural gas wells Crude oil wells Total wells
Gross Net Gross Net Gross Net
---------------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Northeast British Columbia 1,568 1,297.5 223 191.4 1,791 1,488.9
Northwest Alberta 2,173 1,696.6 588 334.5 2,761 2,031.1
Northern Plains 4,057 3,281.8 5,800 5,276.2 9,857 8,558.0
Southern Plains 7,405 6,236.6 1,169 1,073.3 8,574 7,309.9
Southeast Saskatchewan 2 2.0 1,239 878.7 1,241 880.7
Non-core regions 69 24.2 127 23.8 196 48.0
UNITED STATES 4 0.4 2 0.3 6 0.7
NORTH SEA UK SECTOR 2 0.1 111 93.8 113 93.9
OFFSHORE WEST AFRICA
Cote d'Ivoire - - 23 13.4 23 13.4
---------------------------------------------------------------------------------------------------------------------------------
Total 15,280 12,539.2 9,282 7,885.4 24,562 20,424.6
=================================================================================================================================
Any reserves data in the following property report is based on the applicable
independent engineering report. See "Conventional Crude Oil, NGLs and Natural
Gas Reserves" and "Oil Sands Mining Reserves".
NORTHEAST BRITISH COLUMBIA
[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the NE BC Area]
Significant geological variation extends throughout the productive reservoirs
in this region located west of the British Columbia and Alberta border to
Prince George, producing light crude oil, NGLs and natural gas.
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 shale gas plays. The
2006 acquisition of ACC significantly increased the asset base in this area.
The southern portion of this region encompasses the Company's BC Foothills
assets where natural gas is produced from the deep Mississippian and Triassic
aged reservoirs in this highly deformed structural area.
23 Canadian Natural Resources Limited
NORTHWEST ALBERTA
[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the NE AB Area]
This region is 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 Rio Alto Exploration; 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 provide a premium developed and undeveloped
land base in the deep basin, multi-zone gas fairway and the Peace River Arch
assets provide 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. The south western portion of this region also contains significant
Foothills assets with natural gas produced from the deep Mississippian and
Triassic aged reservoirs.
NORTHERN PLAINS
[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the Northern Plains Area]
Canadian Natural Resources Limited 24
This region extends just south of Edmonton north to Fort McMurray and from the
Northwest Alberta area 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.
Natural gas in this region is produced from shallow, low-risk, multi-zone
prospects and more recently from the Horseshoe Canyon CBM. The Company targets
low-risk exploration and development opportunities and plans to expand its
commercial Horseshoe Canyon CBM project. Evaluation of the potential production
of CBM from the Mannville coals commenced in 2006 with the drilling of three
horizontal wells. The three well pilot was deemed not commercial and the wells
were suspended in 2008.
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% 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 the
result of Crown land purchases and several acquisitions including Sceptre
Resources, Ranger Oil and Petrovera, as well as acquisitions from Koch
Exploration. Included in this area is the 100% owned ECHO Pipeline system which
is a high temperature, insulated crude oil transportation pipeline that
eliminates the requirement for field condensate blending. The pipeline, which
has a capacity of up to 72,000 bbl/d, 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.
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 14(Degree)-17(Degree)
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, including the 62% owned and operated
Pelican Lake Pipeline. The Company holds and controls approximately 75% of the
known Wabasca crude oil pool in the Pelican Lake area. It is estimated the
Wabasca pool contains approximately four billion barrels of original crude oil
in place but is only expected to achieve less than a 5% average recovery factor
using primary production on the Company's developed leases. The Company is
using an Enhanced Oil Recovery ("EOR") scheme through both water and polymer
flooding to increase the ultimate recoveries from the field. To date
approximately 11% of the field has been converted to waterflood and there are
three producing polymer production wells and 70 polymer injection wells.
Pelican Lake production averaged approximately 37,000 bbl/d in 2008
(2007-34,000 bbl/d). The Company is continuing to drill and convert wells to
polymer injection in 2009.
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 (CSS) 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 119,500 bbl/d, and the 15% Company owned
Cold Lake Pipeline. The Company also holds a 50% 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 1999, 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. A
mature SAGD heavy oil project in which the Company holds a 50% interest is also
in operation in the Saskatchewan portion of this region. The Regulatory
application for the Kirby In-Situ Oil Sands Project located approximately 85 km
northeast of Lac La Biche was submitted in September 2007 outlining the
Company's plan to build a 45,000 bbl/d in-situ oil sands project. Final
corporate sanction and project scope will be impacted by environmental
regulations and their associated costs. Subject to regulatory approval, crude
oil pricing, and capital costs, the Company may proceed with the detailed
engineering and design work.
25 Canadian Natural Resources Limited
In 2007 the Company received regulatory approval for 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 Company began construction in 2007 and first oil production was achieved in
late October 2008. The expansion added 40,000 bbl/d of capacity. Subsequent to
December 31, 2008, operational issues on one of the pads caused steaming to
cease on all well pads resulting in the Company switching from the steaming
cycle to the production cycle ahead of schedule. The Company is working on
rectifying the issue.
SOUTHERN PLAINS AND SOUTHEAST SASKATCHEWAN
[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the Southern Plans /
Saskatchewan Areas]
The Southern Plains area is principally located south of the Northern Plains
area to the United States border and extending into western Saskatchewan.
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 were augmented by the 2006
acquisition of ACC.
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 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. This region produces primarily light sour crude oil
from as many as seven productive horizons found at depths up to 2,700 meters.
Canadian Natural Resources Limited 26
HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED -- Map of Canadian Natural Lands in the Horizon Oil Sands
Project]
Canadian Natural owns a 100% working interest in its Athabasca Oil Sands leases
in northern Alberta, of which a portion (being lease 18) is subject to a 5% net
carried interest in the bitumen development. The Horizon Project is located on
these leases, about 70 kilometers north of Fort McMurray. Figure 1 shows the
location of the Horizon Project within Alberta and within the region and Table
1 describes the leases the Company holds in the region.
FIGURE 1 - LOCATION OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED -- Map of Horizon Oil Sands Project]
[GRAPHIC OMITTED -- second Map of Horizon Oil Sands Project]
27 Canadian Natural Resources Limited
TABLE 1 - CANADIAN NATURAL ATHABASCA REGION OIL SAND LEASES
Short lease name Official lease number Lease expiry date(1) Area in hectares
---------------------------------------------------------------------------------------
Lease 18 727912T18 Continued Producing(2) 19,988
Lease 10 7400120010 December 14, 2015 3,840
Lease 25 7401050025 May 17, 2016 1,536
Lease 11 7400120011 December 14, 2015 518
Lease 12 7400120012 December 14, 2015 9,216
Lease 13 7400120013 December 14, 2015 69
Lease 15 7400120015 December 14, 2015 1,536
Lease 19 7402050019 May 30, 2017 5,120
Lease 20 7402050020 May 30, 2017 768
Lease 6 7597050T06 May 6, 2012 2,584
Lease 7 7597050T07 May 6, 2012 1,144
=======================================================================================
(1) The Company can apply for an extension of the leases past the expiry date.
(2) Pursuant to Section 14 of the Oil Sands Tenure Regulation.
The leases being developed for the Horizon Project are 18, 25, 10, 19 and 20.
The project site is accessible by a private road as well as a private airstrip.
The project includes surface oil sands mining, bitumen extraction, bitumen
upgrading and associated infrastructure. Mining of the oil sands is done using
conventional truck and shovel technology. The ore is then processed through
extraction and froth treatment facilities to produce bitumen, which is upgraded
on-site into 34 O API SCO. The SCO is transported from the site by the Horizon
Pipeline to the Edmonton area for distribution. An on-site cogeneration plant
provides power and steam for the operation.
In June 2002, Canadian Natural filed an application for regulatory approval of
the Horizon Project. 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 the Horizon Project was 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.
Site clearing and pre-construction preparation activities commenced in 2004 and
the Company received project sanction by the Board of Directors in February
2005, authorizing management to proceed with Phase 1 of the Horizon Project.
First synthetic crude oil production was achieved on February 28, 2009. Full
production capacity for Phase 1 is 110,000 bbl/d of SCO and is expected to be
achieved in late 2009.
Subsequent planned expansion through Phases 2/3, further broken down into a
series of four Tranches, are being re-profiled in order to attain better cost
management.
Horizon Project Phase 1 construction costs were approximately $2.7 billion in
2008 and cumulative construction expenditures were approximately $9.5 billion
through the end of 2008. In addition, $364 million of expenditures were
incurred for commissioning costs and operating and capital inventory for Phase
1 and capital expenditures of $336 million were incurred for Phases 2 and 3.
Forecasted expenditures of $621 million are expected to be incurred in 2009 for
remaining Phase 1 construction costs, commissioning and inventory costs, as
well as sustaining capital costs and Tranche 2 expansion. The total
construction cost to completion is expected to be 43% over the original $6.8
billion estimate. These expenditures are direct project costs only and do not
include capitalized interest, stock based compensation or lease evaluation.
During the fourth quarter 2008, the Company drilled 92 stratigraphic test wells
(2007 - 98, 2006 - 163) to further delineate the ore body and confirm resource
quality and quantity.
Canadian Natural Resources Limited 28
As of year-end 2008, key development achievements associated with the Horizon
Project were as follows:
o Phase 1 work progress is 98.9% complete.
o Mine operations has removed 87.8 million bank cubic meters of
overburden material.
REGIONAL AND PROJECT GEOLOGY
Lease 18, the main oil sands 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.
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 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 general stratigraphy of the
Horizon Project is shown in Figure 2.
FIGURE 2 - GENERAL STRATIGRAPHY OF THE HORIZON OIL SANDS PROJECT
[GRAPHIC OMITTED -- General Stratigraphy]
29 Canadian Natural Resources Limited
OIL SANDS MINING RESERVES
The following table sets out Canadian Natural's net reserves, after royalties,
of synthetic crude oil from the Horizon Project:
Constant Prices
As at December 31, 2008
--------------------------------------------------------------------------------
Proved and
Proved Total Probable
--------------------------------------------------------------------------------
Net reserves, after royalties (mmbbl)
Synthetic crude oil 1,946 2,944
================================================================================
NOTE: SYNTHETIC CRUDE OIL RESERVES ARE BASED ON THE UPGRADING OF BITUMEN USING
TECHNOLOGIES IMPLEMENTED AT THE HORIZON PROJECT.
For the year ended December 31, 2008, the Company retained GLJ to evaluate 100%
of Phase 1 to Phase 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 2.9 billion barrels of net proved
and probable synthetic crude oil reserves shown in the table are produced from
38 years of projected production commencing in 2009.
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 Reserves 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.
Canadian Natural Resources Limited 30
FIGURE 3 - HORIZON OIL SANDS PROJECT RESOURCE AREAS AND GENERAL LAYOUT
[GRAPHIC OMITTED --- map]
31 Canadian Natural Resources Limited
FIGURE 4 - HORIZON OIL SANDS PROJECT CORE HOLE COVERAGE
[GRAPHIC OMITTED -- map]
Canadian Natural Resources Limited 32
UNITED KINGDOM NORTH SEA
[GRAPHIC OMITTED -- map]
Through its wholly owned subsidiary CNR International (U.K.) Limited, formerly
Ranger Oil (U.K.) Limited, the Company has operated in the North Sea for over
30 years and has developed a significant database, extensive operating
experience and an experienced staff. In 2008, the Company produced from 13
crude oil fields.
The northerly fields are centered around the Ninian Field where the Company has
an 87.1% 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% to 100%. The Company also has an
interest in the Strathspey Field and 12 licences covering 20 exploration blocks
and part blocks surrounding the Ninian and Murchison platforms. The Company
also has a 66.5% working interest in the abandoned Hutton Field.
In the central portion of the North Sea, the Company holds a 87.6% operated
working interest in the Banff Field and also owns a 45.7% operated working
interest in the Kyle Field. Production from the Kyle Field is processed through
the Banff FPSO facilities resulting in lower combined production costs from
these fields.
The Company holds a 100% operated working interest in T-block (comprising the
Tiffany, Toni and Thelma Fields).
The Company receives tariff revenue from other field owners for the processing
of crude oil and natural gas through some of the processing facilities.
Opportunities for further long-reach well development on adjacent fields are
provided by the existing processing facilities.
During 2008 two production wells were completed at Murchison and one production
well was completed at Ninian with an additional well in progress at Ninian at
year end. The Company also drilled one water injection well at Ninian and
further increased volumes injected in to the Ninian reservoir.
The Company continued with its planned investment in its long-term facilities
and infrastructure strategy and successfully carried our maintenance
turnarounds at all five installations during the year. With the Murchison
turnaround, the Company implemented a new control system which has resulted in
improved platform uptime.
In the first quarter 2009, the Company commenced drilling on Deep Banff a high
temperature, high pressure, natural gas exploration well. Upon successful
discovery the net interest to the Company increases from 18% to 37%. Results
are expected in the second quarter of 2009.
33 Canadian Natural Resources Limited
OFFSHORE WEST AFRICA
COTE D'IVOIRE
[GRAPHIC OMITTED]
The Company owns interests in two exploration licences offshore Cote d'Ivoire.
The Company has a 58.7% operated interested in the Espoir Field in Block CI-26
which is located in water depths ranging from 100 to 700 meters. Production
from East Espoir commenced in 2002 and development drilling of West Espoir was
completed in 2008. 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. Progress on the Facility Upgrade Project
to increase capacity of the FPSO continues and is expected to be completed in
third quarter 2009.
The Company also has a 58% interest in the Baobab Field, identified in Block
CI-40, which is eight kilometers south of the Espoir facilities. Problems with
the control of sand and solids production led to five of the ten production
wells at Baobab being shut in during 2007. The Company secured a deepwater rig
that was mobilized in early second quarter 2008 which enabled work to begin on
the restoration of the shut-in production with three wells being onstream by
year end. A fourth and final well is expected to be completed in the second
quarter of 2009.
To date political unrest which has occurred from time to time 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.
Canadian Natural Resources Limited 34
GABON
[GRAPHIC OMITTED][GRAPHIC OMITTED]
The Company has a permit comprising a 90% operating interest in the production
sharing agreement for the block containing the Olowi Field. The field is
located about 20 kilometers from the Gabonese coast and in 30 meters water
depth. Delays in construction of the FPSO which arrived on location in February
2009, have resulted in first oil being expected in the first half of 2009. Two
appraisal wells and two production wells have been drilled and development
activity is continuing. It is planned that in total 28 horizontal production
wells plus one gas injector well will be drilled. Crude oil production will
rely on a gas cap expansion supplemented by re-injection of the produced
solution gas. Production is expected to ramp up to a plateau rate of
approximately 20,000 bbl/d in 2010.
35 Canadian Natural Resources Limited
B. CONVENTIONAL CRUDE OIL, NGLS, AND NATURAL GAS RESERVES
For the year ended December 31, 2008, the Company retained a qualified
independent reserves evaluator, Sproule Associates Limited ("Sproule"), to
evaluate 100% of the Company's conventional proved, as well as proved and
probable crude oil, NGLs and natural gas reserves and prepare Evaluation
Reports on these reserves. Conventional crude oil, NGLs and natural gas
reserves include all of the Company's light/medium, primary heavy, and thermal
heavy crude oil, natural gas, coal bed methane and NGLs reserves. They do not
include the Company's oil sands mining reserves. The Company has been granted
an exemption from certain of the provisions of 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 three principal differences between the two standards. The
first is 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. 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 third is the requirement to disclose a gross
reserve reconciliation (before the consideration of royalties). The Company
discloses its conventional crude oil, NGLs, and natural gas reserve
reconciliations net of royalties in adherence to SEC requirements.
The Company annually discloses 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 and in its
annual Form 40-F filing with the SEC. 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. 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 additional voluntary
information, which is disclosed in this Annual Information Form.
The Reserves Committee of the Company's Board of Directors has met with and
carried out independent due diligence procedures with Sproule to review the
qualifications of and procedures used by the evaluator in determining the
estimate of the Company's quantities and net present value of remaining
conventional crude oil, NGLs and natural gas reserves.
The following tables summarize the evaluations of conventional reserves and
estimated net present values of these reserves at December 31, 2008.
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 MATERIAL.
Canadian Natural Resources Limited 36
NET CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES (NET OF ROYALTIES)
Constant Prices and Costs
-----------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Total proved & Total proved &
Total proved reserves probable reserves Total proved reserves probable reserves
-----------------------------------------------------------------------------------------------------------------------------------
NORTH AMERICA
Canada 948 1,599 3,521 4,617
United States - - 2 2
INTERNATIONAL
United Kingdom 256 399 67 94
Cote d'Ivoire 124 170 94 131
Gabon 18 21 - -
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL 1,346 2,189 3,684 4,844
===================================================================================================================================
CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES
Constant Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Company gross Net Company gross Net
----------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves 704 632 3,271 2,824
Proved undeveloped reserves 766 714 980 860
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES 1,470 1,346 4,251 3,684
TOTAL PROVED & PROBABLE RESERVES 2,371 2,189 5,584 4,844
===================================================================================================================================
ESTIMATED NET PRESENT VALUE
Constant Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
Undiscounted Discounted at:
($ millions) 10% 15% 20%
----------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves $ 19,328 12,987 11,253 9,980
Proved undeveloped reserves $ 7,690 2,200 1,164 521
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES $ 27,018 15,187 12,417 10,501
TOTAL PROVED & PROBABLE RESERVES $ 39,216 19,264 15,179 12,484
===================================================================================================================================
37 Canadian Natural Resources Limited
CONVENTIONAL CRUDE OIL, NGLS AND NATURAL GAS RESERVES
Forecast Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
Crude oil & NGLs (mmbbl) Natural gas (bcf)
Company gross Net Company gross Net
----------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves 813 683 3,355 2,813
Proved undeveloped reserves 750 604 985 827
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES 1,563 1,287 4,340 3,640
TOTAL PROVED & PROBABLE RESERVES 2,430 1,968 5,702 4,759
===================================================================================================================================
ESTIMATED NET PRESENT VALUES
Forecast Prices and Costs
----------------------------------------------------------------------------------------------------------------------------------
($ millions) Undiscounted Discounted at:
10% 15% 20%
----------------------------------------------------------------------------------------------------------------------------------
Proved developed reserves $ 46,341 $ 25,995 $ 21,552 $ 18,522
Proved undeveloped reserves $ 35,554 $ 11,992 $ 8,096 $ 5,744
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED RESERVES $ 81,895 $ 37,987 $ 29,648 $ 24,266
TOTAL PROVED & PROBABLE RESERVES $ 130,876 $ 52,770 $ 39,560 $ 31,427
===================================================================================================================================
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.
Canadian Natural Resources Limited 38
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% probability that the quantities actually recovered will equal or
exceed the stated values. The Company has elected to disclose proved and
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 and 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.
9. The constant price and cost case assumes that prices in effect at year-end
2008 adjusted for quality and transportation as well as the 2008 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 2008 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$0.82/C$1.00):
Natural gas | Crude oil & NGLs
--------------------------------------------------------------|----------------------------------------------------------------
Company | Company Hardisty
average Henry Hub Huntingdon/ | average WTI @ Heavy Edmonton North Sea
price Louisiana AECO Sumas | price Cushing(1) 12(degree) API Par(2) Brent
(Year) (C$/mcf) (US$/mmbtu) (C$/mmbtu) (C$/mmbtu) | (C$/bbl) (US$/bbl) (C$/bbl) (C$/bbl) (US$/bbl)
--------------------------------------------------------------|----------------------------------------------------------------
2008 6.51 5.63 6.34 7.48 | 34.51 44.60 26.11 45.51 41.76
==============================================================|================================================================
(1) "WTI @ CUSHING" REFERS TO THE PRICE OF WEST TEXAS INTERMEDIATE CRUDE
OIL AT CUSHING, OKLAHOMA.
(2) "EDMONTON PAR" REFERS TO THE PRICE OF LIGHT GRAVITY (40(degree) 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. Costs are
escalated at 2% per year. Future crude oil, NGLs and natural gas price
forecasts were based on Sproule's December 31, 2008 crude oil, NGLs and
natural gas pricing model.
39 Canadian Natural Resources Limited
The Company's weighted average crude oil and NGLs price and the weighted
average natural gas price in the 2008 evaluation were $34.51 per barrel
and $6.51 per mcf respectively. The crude oil and natural gas forecast
prices used in the Evaluation Reports are as follows:
Natural gas | Crude oil & NGLs
-------------------------------------------------------------|-----------------------------------------------------------------
Company | Company Hardisty
average Henry Hub Huntingdon/ | average WTI @ Heavy Edmonton North Sea
price Louisiana AECO Sumas | price Cushing(1) 12(degree) API Par(2) Brent
(Year) (C$/mcf) (US$/mmbtu) (C$/mmbtu) (C$/mmbtu) | (C$/bbl) (US$/bbl) (C$/bbl) (C$/bbl) (US$/bbl)
-------------------------------------------------------------|-----------------------------------------------------------------
2009 6.73 6.30 6.82 6.82 53.07 53.73 47.05 65.35 51.73
2010 7.46 7.32 7.56 7.56 | 62.06 63.41 54.58 72.78 61.37
2011 7.74 7.56 7.84 7.84 | 68.50 69.53 59.96 79.95 67.45
2012 8.26 8.49 8.38 8.38 | 77.12 79.59 67.53 86.57 77.47
2013 9.07 9.74 9.20 9.20 | 86.07 92.01 74.08 94.97 89.84
2014 9.26 9.94 9.41 9.41 | 88.99 93.85 75.58 96.89 91.64
2015 9.46 10.14 9.62 9.62 | 90.95 95.72 77.10 98.85 93.47
2016 9.67 10.34 9.83 9.83 | 94.64 97.64 78.66 100.84 95.34
2017 9.88 10.54 10.05 10.05 | 98.04 99.59 80.25 102.88 97.25
2018 10.08 10.76 10.27 10.27 | 99.21 101.58 81.87 104.96 99.19
2019 10.32 10.97 10.50 10.50 | 100.38 103.61 83.52 107.08 101.18
============================================================|=================================================================
NOTE: FOREIGN EXCHANGE RATE USED WAS US$0.80/C$1.00 FOR 2009;
US$0.85/C$1.00 FOR 2010 AND 2011; US$0.90/C$1.00 FOR 2012; AND
US$0.95/C$1.00 FOR 2013 AND BEYOND.
11. Estimated future net revenue from all assets is income derived from the
sale of net reserves of crude oil, natural gas and NGLs, less all capital
costs, production taxes, and operating costs and before provision for
income taxes, administrative overhead costs and existing asset abandonment
liabilities.
12. The estimated total development capital costs net to the Company necessary
to achieve the estimated future net "proved" and "proved and probable"
production revenues are:
Proved Proved & probable
($ millions) Forecast price case Constant price case Forecast price case Constant price case
----------------------------------------------------------------------------------------------------------------------------
2009 1,592 1,589 1,841 1,841
2010 1,646 1,613 1,938 1,900
2011 1,657 1,590 2,168 2,081
2012 883 832 1,409 1,328
2013 1,122 1,037 1,709 1,579
2014 620 562 814 737
2015 390 346 566 503
2016 605 527 661 576
2017 477 407 832 710
2018 286 239 544 455
2019 221 181 300 246
Thereafter 1,972 1,054 3,428 2,302
============================================================================================================================
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 to be reasonable and no field inspection was
conducted.
Canadian Natural Resources Limited 40
A report on conventional reserves data by Sproule 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 and oil sands mining 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 or oil sands mining
reserves with any U. S. agency or federal authority other than the SEC.
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, DEC 31, 2006 887 299 130 1,316 | 3,705 37 56 3,798
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries 30 - - 30 | 134 - - 134
Infill drilling 10 6 - 16 | 124 3 - 127
Improved recovery 3 - - 3 | 8 - - 8
Property purchases 1 - - 1 | 12 - - 12
Property disposals - (3) - (3) | - - - -
Production (77) (20) (10) (107) | (503) (5) (4) (512)
Revisions of prior estimates 66 28 8 102 | 41 46 12 99
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2007 920 310 128 1,358 | 3,521 81 64 3,666
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries 51 - - 51 | 140 - - 140
Infill drilling 7 6 4 17 | 46 (1) 6 51
Improved recovery 10 - - 10 | 6 - - 6
Property purchases - - - - | 77 - - 77
Property disposals - - - - | (1) - - (1)
Production (76) (17) (8) (101) | (449) (4) (4) (457)
Economic revisions due to prices 28 (81) 8 (45) | (19) (56) 6 (69)
Revisions of prior estimates 8 38 10 56 | 202 47 22 271
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2008 948 256 142 1,346 | 3,523 67 94 3,684
-----------------------------------------------------------------------------------|------------------------------------------------
|
PROVED AND PROBABLE RESERVES |
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2006 1,502 422 195 2,119 | 4,857 93 99 5,049
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries 41 - - 41 | 177 - - 177
Infill drilling 52 6 - 58 | 163 3 - 166
Improved recovery 4 - - 4 | 8 - - 8
Property purchases 2 6 - 8 | 17 1 - 18
Property disposals - (3) - (3)| (1) - - (1)
Production (77) (20) (10) (107)| (503) (5) (4) (512)
Revisions of prior estimates 21 (6) 1 16 | (116) 21 (7) (102)
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2007 1,545 405 186 2,136 | 4,602 113 88 4,803
-----------------------------------------------------------------------------------|------------------------------------------------
Extensions & discoveries 76 - - 76 | 182 - - 182
Infill drilling 9 4 - 13 | 58 (3) - 55
Improved recovery 23 - - 23 | 8 - - 8
Property purchases 6 - - 6 | 93 - - 93
Property disposals - - - - | (6) - - (6)
Production (76) (17) (8) (101) | (449) (4) (4) (457)
Economic revisions due to prices 59 (45) 8 22 | (27) (63) 8 (82)
Revisions of prior estimates (43) 52 5 14 | 158 51 39 248
-----------------------------------------------------------------------------------|------------------------------------------------
RESERVES, DEC 31, 2008 1,599 399 191 2,189 | 4,619 94 131 4,844
===================================================================================|================================================
NOTE: Revisions of prior year estimates for 2007 include revisions due to
prices.
41 Canadian Natural Resources Limited
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 2008 Annual Report under "Supplementary Oil and
Gas Information" on pages 101 to 105 and is incorporated herein by reference.
D. CRUDE OIL, NGLS AND NATURAL GAS PRODUCTION
The Company's working interest share of crude oil, NGLs and natural gas
production and revenues received for the last three financial years is
summarized in the following tables:
Year Ended Dec 31
|----------|
| 2008 | 2007 2006
-----------------------------------------|----------|--------------------------
Daily production, before royalties | |
Crude oil and NGLs (bbl/d) | 315,667 | 331,232 331,998
Natural gas (mmcf/d) | 1,495 | 1,668 1,492
-----------------------------------------|----------|--------------------------
Annual production, before royalties | |
Crude oil and NGLs (mbbl) | 115,534 | 120,900 121,179
Natural gas (bcf) | 547 | 609 545
=========================================|==========|==========================
Canadian Natural Resources Limited 42
NETBACKS
INFORMATION BY QUARTER
2008 2007
Q1 Q2 Q3 Q4 YEAR ENDED| Q1 Q2 Q3 Q4 Year Ended
------------------------------------------------------------------------------|----------------------------------------------------
AVERAGE DAILY PRODUCTION |
VOLUMES, BEFORE ROYALTIES |
|
Crude oil and NGLs |
(bbl/d) 327,217 319,077 306,970 309,570 315,667| 327,001 327,494 333,062 337,240 331,232
Natural gas (mmcf/d) 1,538 1,526 1,490 1,427 1,495| 1,717 1,722 1,647 1,589 1,668
------------------------------------------------------------------------------|----------------------------------------------------
|
PRODUCT NETBACKS (1) |
Crude oil and NGLs ($/bbl) |
Sales price (2) $ 78.99 $ 103.73 $ 102.30 $ 45.81 $ 82.41| $ 51.71 $ 53.74 $ 58.10 $ 58.03 $ 55.45
Royalties 8.70 14.82 14.17 4.49 10.48| 4.92 5.46 6.65 6.66 5.94
Production |
expenses 14.81 16.39 17.61 16.33 16.26| 13.81 15.01 13.13 11.53 13.34
------------------------------------------------------------------------------|----------------------------------------------------
NETBACK $ 55.48 $ 72.52 $ 70.52 $ 24.99 $ 55.67| $ 32.98 $ 33.27 $ 38.32 $ 39.84 $ 36.17
------------------------------------------------------------------------------|----------------------------------------------------
|
Natural gas ($/mcf) |
Sales price (2) $ 7.77 $ 9.89 $ 8.82 $ 7.03 $ 8.39| $ 7.74 $ 7.44 $ 5.87 $ 6.28 $ 6.85
Royalties 1.35 1.86 1.55 1.08 1.46| 1.48 1.10 0.89 0.94 1.11
Production |
expenses 1.03 0.94 1.05 1.06 1.02| 0.97 0.89 0.88 0.91 0.91
------------------------------------------------------------------------------|----------------------------------------------------
NETBACK $ 5.39 $ 7.09 $ 6.22 $ 4.89 $ 5.91| $ 5.29 $ 5.45 $ 4.10 $ 4.43 $ 4.83
------------------------------------------------------------------------------|----------------------------------------------------
|
CRUDE OIL AND NGLS NETBACKS BY TYPE(1) |
Light/Pelican Lake/NGLs ($/bbl) |
Sales price (2) $ 89.68 $ 114.69 $ 107.33 $ 53.16 $ 90.88| $ 60.19 $ 64.10 $ 67.34 $ 72.62 $ 65.99
Royalties 11.43 14.59 15.84 5.71 11.83| 4.89 5.87 7.24 8.34 6.57
Production |
expenses 15.09 16.13 17.18 17.92 16.56| 13.85 14.91 14.40 12.64 13.95
------------------------------------------------------------------------------|----------------------------------------------------
NETBACK $ 63.15 $ 83.97 $ 74.30 $ 29.53 $ 62.49| $ 41.45 $ 43.32 $ 45.70 $ 51.64 $ 45.47
------------------------------------------------------------------------------|----------------------------------------------------
|
Heavy crude oil ($/bbl) |
Sales price (2) $ 67.46 $ 92.55 $ 97.20 $ 38.21 $ 73.62| $ 41.24 $ 41.85 $ 48.10 $ 43.06 $ 43.66
Royalties 5.74 15.05 12.47 3.22 9.08| 4.96 4.98 6.00 4.95 5.23
Production |
expenses 14.50 16.65 18.05 14.68 15.95| 13.76 15.12 11.75 10.38 12.66
------------------------------------------------------------------------------|----------------------------------------------------
NETBACK $ 47.22 $ 60.85 $ 66.68 $ 20.31 $ 48.59| $ 22.52 $ 21.75 $ 30.35 $ 27.73 $ 25.77
==============================================================================|====================================================
(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.
43 Canadian Natural Resources Limited
NETBACKS
INFORMATION BY QUARTER
2006
Year
Q1 Q2 Q3 Q4 Ended
-------------------------------------------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION VOLUMES,
BEFORE ROYALTIES
Crude oil and NGLs (bbl/d) 323,662 338,852 321,665 343,705 331,998
Natural gas (mmcf/d) 1,436 1,475 1,437 1,620 1,492
-------------------------------------------------------------------------------------------------------------
PRODUCT NETBACKS(1)
Crude oil and NGLs ($/bbl)
Sales price ((2)) $ 43.79 $ 60.05 $ 62.55 $ 47.27 $ 53.65
Royalties 3.48 5.14 5.11 4.10 4.48
Production
expenses 11.33 11.92 13.47 12.32 12.29
-------------------------------------------------------------------------------------------------------------
Netback $ 28.98 $ 42.99 $ 43.97 $ 30.85 $ 36.88
-------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price ((2)) $ 8.30 $ 6.16 $ 5.83 $ 6.66 $ 6.72
Royalties 1.70 1.11 1.11 1.26 1.29
Production
expenses 0.80 0.80 0.84 0.86 0.82
-------------------------------------------------------------------------------------------------------------
Netback $ 5.80 $ 4.25 $ 3.88 $ 4.54 $ 4.61
-------------------------------------------------------------------------------------------------------------
CRUDE OIL AND NGLS NETBACKS BY TYPE(1)
Light/Pelican Lake/NGLs ($/bbl)
Sales price ((2)) $ 58.28 $ 69.02 $ 71.65 $ 57.68 $ 64.33
Royalties 4.65 5.53 5.39 4.39 5.00
Production
expenses 11.15 11.18 14.12 12.99 12.42
-------------------------------------------------------------------------------------------------------------
Netback $ 42.48 $ 52.31 $ 52.14 $ 40.30 $ 46.91
-------------------------------------------------------------------------------------------------------------
Heavy crude oil ($/bbl)
Sales price ((2)) $ 25.22 $ 50.08 $ 51.38 $ 36.11 $ 41.20
Royalties 1.98 4.71 4.76 3.78 3.88
Production
expenses 11.55 12.73 12.67 11.60 12.15
-------------------------------------------------------------------------------------------------------------
Netback $ 11.69 $ 32.64 $ 33.95 $ 20.73 $ 25.17
=============================================================================================================
(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.
Canadian Natural Resources Limited 44
2008 2007
YEAR | Year
Q1 Q2 Q3 Q4 ENDED | Q1 Q2 Q3 Q4 Ended
-------------------------------------------------------------------------|---------------------------------------------------
SEGMENTED |
|
NORTH AMERICA PRODUCT NETBACKS((1)) |
Light/Pelican Lake/NGLs ($/bbl) |
Sales price |
((2)) $ 82.25 $ 107.38 $ 102.17 $ 44.21 $ 84.00| $ 54.13 $ 56.06 $ 60.26 $ 63.94 $ 58.66
Royalties 16.40 21.68 21.29 8.80 17.20| 8.84 9.22 11.55 12.56 10.57
Production |
expenses 12.80 13.32 13.17 13.68 13.24| 11.74 12.11 11.58 10.82 11.56
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 53.05 $ 72.38 $ 67.70 $ 21.73 $ 53.72| $ 33.55 $ 34.73 $ 37.13 $ 40.56 $ 36.53
-------------------------------------------------------------------------|---------------------------------------------------
|
Heavy crude oil ($/bbl) |
Sales price |
((2)) $ 67.46 $ 92.55 $ 97.20 $ 38.21 $ 73.62| $ 41.24 $ 41.85 $ 48.10 $ 43.06 $ 43.66
Royalties 5.74 15.05 12.47 3.22 9.08| 4.96 4.98 6.00 4.95 5.23
Production |
expenses 14.50 16.65 18.05 14.68 15.95| 13.76 15.12 11.75 10.38 12.66
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 47.22 $ 60.85 $ 66.68 $ 20.31 $ 48.59| $ 22.52 $ 21.75 $ 30.35 $ 27.73 $ 25.77
-------------------------------------------------------------------------|---------------------------------------------------
|
Natural gas ($/mcf) |
Sales price |
((2)) $ 7.74 $ 9.89 $ 8.76 $ 6.94 $ 8.41| $ 7.79 $ 7.47 $ 5.88 $ 6.31 $ 6.87
Royalties 1.36 1.88 1.55 1.09 1.47| 1.50 1.11 0.90 0.95 1.12
Production |
expenses 1.01 0.98 1.03 1.04 1.00| 0.95 0.87 0.87 0.90 0.90
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 5.37 $ 7.08 $ 6.18 $ 4.81 $ 5.88| $ 5.34 $ 5.49 $ 4.11 $ 4.46 $ 4.85
-------------------------------------------------------------------------|---------------------------------------------------
|
NORTH SEA PRODUCT NETBACKS((1)) |
Light crude oil ($/bbl) |
Sales price |
((2)) $ 99.01 $ 129.57 $ 109.82 $ 63.07 $ 100.31| $ 68.83 $ 73.18 $ 77.55 $ 83.44 $ 74.99
Royalties 0.91 0.27 0.24 0.12 0.21| 0.13 0.13 0.14 0.19 0.14
Production |
expenses 22.35 25.61 29.21 28.77 26.29| 18.57 22.11 23.61 18.95 20.78
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 76.47 $ 103.69 $ 80.37 $ 34.18 $ 73.81| $ 50.13 $ 50.94 $ 53.80 $ 64.30 $ 54.07
-------------------------------------------------------------------------|---------------------------------------------------
|
Natural Gas ($/mcf) |
Sales price |
((2)) $ 3.30 $ 4.27 $ 3.65 $ 5.19 $ 4.09| $ 4.49 $ 3.92 $ 5.26 $ 3.62 $ 4.26
Royalties - - - - -| - - - - -
Production |
expenses 2.33 2.68 3.09 1.96 2.51| 2.58 2.26 2.29 1.50 2.17
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 0.97 $ 1.59 $ 0.56 $ 3.23 $ 1.58| $ 1.91 $ 1.66 $ 2.97 $ 2.12 $ 2.09
-------------------------------------------------------------------------|---------------------------------------------------
|
OFFSHORE WEST AFRICA PRODUCT NETBACKS((1)) |
Light crude oil ($/bbl) |
Sales price |
((2)) $ 96.31 $ 114.56 $ 125.71 $ 65.80 $ 97.96| $ 58.60 $ 72.84 $ 70.52 $ 81.89 $ 71.68
Royalties 17.43 14.49 26.90 4.71 14.81| 3.70 7.12 6.81 7.59 6.40
Production |
expenses 8.03 9.79 7.74 14.47 10.29| 8.93 7.98 7.00 9.32 8.32
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 70.85 $ 90.28 $ 91.07 $ 46.62 $ 72.86| $ 45.97 $ 57.74 $ 56.71 $ 64.98 $ 56.96
-------------------------------------------------------------------------|---------------------------------------------------
|
Natural gas ($/mcf) |
Sales price |
((2)) $ 7.89 $ 8.97 $ 11.18 $ 12.54 $ 10.03| $ 5.97 $ 6.22 $ 5.31 $ 5.49 $ 5.68
Royalties 1.43 1.13 2.24 1.26 1.52| 0.38 0.59 0.51 0.52 0.51
Production |
expenses 1.25 1.27 1.58 2.51 1.61| 1.48 1.10 1.39 1.89 1.48
-------------------------------------------------------------------------|---------------------------------------------------
NETBACK $ 5.21 $ 6.57 $ 7.36 $ 8.77 $ 6.90| $ 4.11 $ 4.53 $ 3.41 $ 3.08 $ 3.69
=========================================================================|===================================================
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Netof transportation and blending costs and excluding risk management
activities.
45 Canadian Natural Resources Limited
2006
Year
Q1 Q2 Q3 Q4 Ended
-----------------------------------------------------------------------------------------------------------------------
SEGMENTED
NORTH AMERICA PRODUCT NETBACKS((1))
Light/Pelican Lake/NGLs ($/bbl)
Sales price ((2)) $ 48.83 $ 64.35 $ 65.15 $ 48.47 $ 56.52
Royalties 8.98 10.87 10.86 7.80 9.59
Production expenses 9.86 9.75 10.81 13.18 10.93
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 29.99 $ 43.73 $ 43.48 $ 27.49 $ 36.00
-----------------------------------------------------------------------------------------------------------------------
-----------------------------------------------------------------------------------------------------------------------
Heavy Crude Oil ($/bbl)
Sales price ((2)) $ 25.22 $ 50.08 $ 51.38 $ 36.11 $ 41.20
Royalties 1.98 4.71 4.76 3.78 3.88
Production expenses 11.55 12.73 12.67 11.60 12.15
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 11.69 $ 32.64 $ 33.95 $ 20.73 $ 25.17
-----------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price ((2)) $ 8.39 $ 6.21 $ 5.86 $ 6.70 $ 6.77
Royalties 1.73 1.13 1.12 1.29 1.31
Production expenses 0.79 0.79 0.83 0.84 0.81
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 5.87 $ 4.29 $ 3.91 $ 4.57 $ 4.65
-----------------------------------------------------------------------------------------------------------------------
NORTH SEA PRODUCT NETBACKS((1))
Light crude oil ($/bbl)
Sales price ((2)) $ 68.05 $ 73.19 $ 78.68 $ 67.72 $ 72.62
Royalties 0.12 0.17 0.11 0.14 0.13
Production expenses 16.85 17.18 20.28 14.76 17.57
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 51.08 $ 55.84 $ 58.29 $ 52.82 $ 54.92
-----------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price ((2)) $ 2.38 $ 2.33 $ 2.38 $ 3.48 $ 2.66
Royalties - - - - -
Production expenses 1.26 1.47 1.30 1.54 1.40
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 1.12 $ 0.86 $ 1.08 $ 1.94 $ 1.26
-----------------------------------------------------------------------------------------------------------------------
OFFSHORE WEST AFRICA PRODUCT NETBACKS((1))
Light crude oil ($/bbl)
Sales price ((2)) $ 65.23 $ 72.97 $ 70.59 $ 63.50 $ 67.99
Royalties 1.55 1.87 4.89 3.02 2.81
Production expenses 6.08 5.61 7.97 10.05 7.45
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 57.60 $ 65.49 $ 57.73 $ 50.43 $ 57.73
-----------------------------------------------------------------------------------------------------------------------
Natural gas ($/mcf)
Sales price ((2)) $ 5.59 $ 5.30 $ 4.97 $ 5.72 $ 5.37
Royalties 0.13 0.14 0.34 0.27 0.22
Production expenses 1.00 0.36 1.39 2.01 1.19
-----------------------------------------------------------------------------------------------------------------------
NETBACK $ 4.46 $ 4.80 $ 3.24 $ 3.44 $ 3.96
=======================================================================================================================
(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.
Canadian Natural Resources Limited 46
E. 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.
CAPITAL EXPENDITURES BY YEAR (1)
Year Ended Dec 31
|-----------|
($ millions) | 2008 | 2007
---------------------------------------------------|-----------|--------------
Net property acquisitions (dispositions)((2)) | 336 | (39)
Land acquisition and retention | 86 | 95
Seismic evaluations | 107 | 124
Well drilling, completion and equipping | 1,664 | 1,642
Production and related facilities | 1,282 | 1,205
---------------------------------------------------|-----------|--------------
Total net reserve replacement expenditures | 3,475 | 3,027
---------------------------------------------------|-----------|--------------
Horizon Project: | |
Phase 1 construction costs | 2,732 | 2,740
Phase 1 operating and capital inventory | 87 | -
Phase 1 commissioning costs | 277 | -
Phase 2/3 costs | 336 | 124
Capitalized interest, stock-based | |
compensation and other | 480 | 437
---------------------------------------------------|-----------|--------------
Total Horizon Project ((3)) | 3,912 | 3,301
---------------------------------------------------|-----------|--------------
Midstream | 9 | 6
Abandonments ((4)) | 38 | 71
Head office | 17 | 20
---------------------------------------------------|-----------|--------------
TOTAL NET CAPITAL EXPENDITURES | 7,451 | 6,425
===================================================|===========|==============
47 Canadian Natural Resources Limited
CAPITAL EXPENDITURES BY QUARTER (1)
2008 Three Months Ended
($ millions) Mar 31 Jun 30 Sep 30 Dec 31
-----------------------------------------------------------------------------------------------------------------------
Net property acquisitions (dispositions) ((2)) $ (8) $ 263 $ 47 $ 34
Land acquisition and retention 12 24 32 18
Seismic evaluation 27 18 40 22
Well drilling, completion and equipping 452 286 421 505
Production and related facilities 319 270 311 382
-----------------------------------------------------------------------------------------------------------------------
Total net reserve replacement expenditures 802 861 851 961
-----------------------------------------------------------------------------------------------------------------------
Horizon Project:
Phase 1 construction costs 665 875 635 557
Phase 1 operating and capital inventory 41 14 27 5
Phase 1 commissioning costs 49 34 84 110
Phase 2/3 costs 77 82 83 94
Capitalized interest, stock-based
compensation and other 109 247 46 78
-----------------------------------------------------------------------------------------------------------------------
Total Horizon Project ((3)) 941 1,252 875 844
-----------------------------------------------------------------------------------------------------------------------
Midstream 1 3 2 3
Abandonments ((4)) 6 7 10 15
Head office 3 4 6 4
-----------------------------------------------------------------------------------------------------------------------
Total net capital expenditures $ 1,753 $ 2,127 $ 1,744 $ 1,827
=======================================================================================================================
CAPITAL EXPENDITURES BY QUARTER (1)
2007 Three Months Ended
($ millions) Mar 31 Jun 30 Sep 30 Dec 31
-----------------------------------------------------------------------------------------------------------------------
Net property acquisitions (dispositions) ((2)) $ 46 $ 15 $ 7 $ (107)
Land acquisition and retention 29 22 29 15
Seismic evaluation 50 34 23 17
Well drilling, completion and equipping 714 288 299 341
Production and related facilities 334 243 238 390
-----------------------------------------------------------------------------------------------------------------------
Total net reserve replacement expenditures 1,173 602 596 656
-----------------------------------------------------------------------------------------------------------------------
Horizon Project
Phase 1 construction costs 674 704 671 691
Phase 2/3 costs 44 19 28 33
Capitalized interest, stock-based
compensation and other 91 118 120 108
-----------------------------------------------------------------------------------------------------------------------
Total Horizon Project ((3)) 809 841 819 832
-----------------------------------------------------------------------------------------------------------------------
Midstream 2 - 2 2
Abandonments ((4)) 20 13 22 16
Head office 5 4 3 8
-----------------------------------------------------------------------------------------------------------------------
Total net capital expenditures $ 2,009 $ 1,460 $ 1,442 $ 1,514
=======================================================================================================================
(1) Net capital expenditures exclude adjustments related to differences
between carrying value and tax value, and other fair value adjustments.
(2) Includes business combinations.
(3) Net capital expenditures for the horizon project also include the impact
of intersegment eliminations.
(4) Abandonments represent expenditures to settle aro and have been reflected
as capital expenditures in this table.
Canadian Natural Resources Limited 48
F. Developed and undeveloped acreage
The following table summarizes the Company's working interest holdings in core
region developed and undeveloped acreage as at December 31, 2008:
(thousands) Developed Acreage Undeveloped Acreage Total Acreage
--------------------------------------------------------------------------------------------------------------------------
Gross Acres Net Acres Gross Acres Net Acres Gross Acres Net Acres
--------------------------------------------------------------------------------------------------------------------------
North America
Alberta 6,249 4,955 10,185 8,675 16,434 13,630
British Columbia 1,470 1,100 3,007 2,200 4,477 3,300
Saskatchewan 799 578 828 715 1,627 1,293
Manitoba 6 6 13 13 19 19
--------------------------------------------------------------------------------------------------------------------------
North Sea
United Kingdom 108 74 314 258 422 332
--------------------------------------------------------------------------------------------------------------------------
Offshore West Africa
Cote d'Ivoire 7 4 95 55 102 59
Gabon - - 152 137 152 137
--------------------------------------------------------------------------------------------------------------------------
Total 8,639 6,717 14,594 12,053 23,233 18,770
==========================================================================================================================
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 Dec 31
|------------|
($ millions, except per common share information) | 2008 | 2007
----------------------------------------------------|------------|--------------
Revenues, before royalties | $ 16,173 | $ 12,543
Net earnings | $ 4,985 | $ 2,608
Per common share - basic and diluted | $ 9.22 | $ 4.84
Adjusted net earnings from operations | $ 3,492 | $ 2,406
Per common share - basic and diluted | $ 6.46 | $ 4.46
Cash flow from operations | $ 6,969 | $ 6,198
Per common share - basic and diluted | $ 12.89 | $ 11.49
Total assets | $ 42,650 | $ 36,114
Total long-term liabilities | $ 20,856 | $ 19,230
----------------------------------------------------|------------|-------------
2008 Three Months Ended
($ millions, except per common share information) Mar 31 Jun 30 Sep 30 Dec 31
-----------------------------------------------------------------------------------------------
Revenues, before royalties $ 3,967 $ 5,112 $ 4,583 $ 2,511
Net earnings (loss) $ 727 $ (347) $ 2,835 $ 1,770
Per common share - basic and diluted $ 1.35 $ (0.65) $ 5.25 $ 3.27
===============================================================================================
2007 Three Months Ended
($ millions, except per common share information) Mar 31 Jun 30 Sep 30 Dec 31
-----------------------------------------------------------------------------------------------
Revenues, before royalties $ 3,118 $ 3,152 $ 3,073 $ 3,200
Net earnings $ 269 $ 841 $ 700 $ 798
Per common share - basic and diluted $ 0.50 $ 1.56 $ 1.30 $ 1.48
===============================================================================================
49 Canadian Natural Resources Limited
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
("Moody's"), "BBB" with a stable outlook by Standard & Poor's ("S&P") and "BBB
(high)" with a negative trend by DBRS Limited ("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.
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 CCC 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 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.
Canadian Natural Resources Limited 50
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.
2008 Monthly Historical Trading on Toronto Stock Exchange
Month High Low Close Volume Traded
-------------------------------------------------------------------------------
January $ 75.99 $ 58.88 $ 64.21 44,123,518
February $ 76.00 $ 60.17 $ 73.76 48,238,701
March $ 76.80 $ 64.00 $ 70.27 42,059,186
April $ 88.36 $ 68.08 $ 85.55 44,070,800
May $ 106.87 $ 81.50 $ 97.24 50,814,542
June $ 111.30 $ 94.73 $ 100.84 50,132,584
July $ 104.83 $ 76.30 $ 80.01 61,435,116
August $ 91.50 $ 73.89 $ 90.64 50,849,698
September $ 89.60 $ 64.40 $ 73.00 74,621,067
October $ 72.89 $ 41.40 $ 60.82 82,264,616
November $ 64.05 $ 34.19 $ 52.00 72,013,144
December $ 49.23 $ 36.75 $ 48.75 59,114,946
================================================================================
On January 20, 2006, the Company announced its intention to make a Normal
Course Issuer Bid through the facilities of TSX 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% 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 TSX 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% of the 538,834,606 common
shares of the Company outstanding on January 15, 2007. No shares were purchased
under the program.
51 Canadian Natural Resources Limited
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 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.
|---------|
| 2008| 2007 2006
-----------------------------------------------|---------|----------------------
| |
Cash dividends declared per common share | $ 0.40| $ 0.34 $ 0.30
===============================================|=========|======================
In February 2009 the Board of Directors approved a 5% increase in the 2008
quarterly dividend from $0.10 per common share to $0.105 per common share,
effective with the April 1, 2009 payment.
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.
Canadian Natural Resources Limited 52
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. Further detail on the Directors and Named Executive Officers are
found in the Company's Management Proxy Circular dated March 18, 2009.
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
Catherine M. Best, FCA Director (2)(4) Interim Chief Financial Officer of Alberta Health
Calgary, Alberta (age 55) Services since 2008 when the Alberta government
Canada consolidated all of the health regions of the province
under one board. Executive Vice-President, Risk Management
and Chief Financial Officer of the Calgary Health Region
(fully integrated publicly funded health care system) from
2002 to 2008; has served continuously as a director of the
Company since November 2003. Currently serving on the
board of directors of Enbridge Income Fund and Superior
Plus Income Fund and is a volunteer member of the Audit
Committee of the Calgary Exhibition and Stampede.
N. Murray Edwards Vice-Chairman and President, Edco Financial Holdings Ltd. (private
Calgary/Banff, Alberta Director (3) management and consulting company). Has served
Canada (age 49) continuously as a director of the Company since September
1988. Currently is Chairman and serving on the board of
directors of Ensign Energy Services Inc. and Magellan
Aerospace Corporation.
Honourable Gary A. Filmon, Director (1)(2) Consultant, The Exchange Group (business consulting
P.C., O.M. (age 66) firm). Has served continuously as a director of the
Winnipeg, Manitoba Company since February 2006. Currently serving on the
Canada board of directors of MTS Allstream Inc., Arctic Glacier
Income Trust, Exchange Industrial Income Fund, Wellington
West Capital Inc. and FWS Construction Inc. and serves as
Chair of Canada's Security and Intelligence Review
Committee.
Ambassador Gordon D. Giffin Director (1)(2) Senior Partner, McKenna Long & Aldridge LLP (law firm)
Atlanta, Georgia (age 59) since May 2001. Has served continuously as a director of
USA the Company since May 2002. Currently serving on the
board of directors of Canadian National Railway Company,
Canadian Imperial Bank of Commerce, Ontario Energy
Savings Corp., and Transalta Corporation.
John G. Langille Vice-Chairman and Director Officer of the Company. Has served continuously as a
Calgary, Alberta (age 63) director of the Company since June 1982.
Canada
Steve W. Laut President and Chief Officer of the Company. Has served continuously as a
Calgary, Alberta Operating Officer and director of the Company since August 2006.
Canada Director
(age 51)
Keith A.J. MacPhail Director (3)(5) Chairman and Chief Executive Officer, Bonavista Energy
Calgary, Alberta (age 52) Trust (oil and gas energy trust) since November 1997 and
Canada Chairman, NuVista Energy Ltd. (an oil and gas
exploration, development and production company) 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, O.C. Chairman and Director (5) Chairman of the Company. Has served continuously as a
Calgary, Alberta (age 63) director of the Company since January 1989.
Canada
53 Canadian Natural Resources Limited
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
Norman F. McIntyre Director (3)(4)(5) Independent businessman. Prior thereto Executive
Calgary, Alberta (age 63) 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 is Chairman and is serving on the board of of
directors of Petro Andina Resources Inc.
Frank J. McKenna, P.C., Director (1)(4) Deputy Chair, TD Bank Financial Group (financial
O.C., (age 61) services). Counsel to Atlantic Canada law firm McInnes
O.N.B., Q.C. Cooper from 1998 to 2005, and most recently Canadian
Cap Pele, New Brunswick Ambassador to the United States from 2005 to 2006. He has
Canada served continuously as a director of the Company since
August 2006. Currently serving on the board of directors
ofBrookfield Asset Management Inc.
James S. Palmer, C.M., Director (3)(4)(5) Chairman and a Partner of Burnet, Duckworth & Palmer LLP
A.O.E., Q.C. (age 80) (law firm). Has served continuously as a director of the
Calgary, Alberta Company since May 1997. Currently serving on the board of
Canada directors of Magellan Aerospace Corporation and is
Director Emeritus of Frontier Oil Corporation.
Dr. Eldon R. Smith, O.C., Director (4)(5) President of Eldon R. Smith & Associates Ltd.,(a private
M.D. (age 69) health care consulting company), and Emeritus Professor
Calgary, Alberta and Former Dean, Faculty of Medicine, University of
Canada Calgary. Has served continuously as a director of the
Company since May 1997. Currently serving on the board of
directors of Vasogen Inc., Aston Hill Financial and
Ventripoint Diagnostics Inc.
David A. Tuer Director (1)(2)(3) Vice-Chairman and Chief Executive Officer of Marble Point
Calgary, Alberta (age 59) Energy Ltd. (private oil and gas exploration company);
Canada Chairman, Calgary Health Region from 2001 to 2008 and
Executive Vice-Chairman BA Energy Inc. from April 2005 to
February 2008 when it was acquired by its parent company
Value Creations Inc. through a Plan of Arrangement and
which until recently was engaged in the development,
building and operations of a merchant heavy oil upgrader
in Northern Alberta for the purpose of upgrading bitumen
and heavy oil feedstock into high-quality crude oils.
Prior thereto President, CEO and a director of Hawker
Resources Inc. from January 2003 to March 2005. Has served
continuously as a director of the Company since May 2002.
Currently serving on the board of directors of Daylight
Resources Trust, Xtreme Coil Drilling Corp., Canadian
Phoenix Resources and Altalink Management LLP., a private
limited partnership.
Real M. Cusson Senior Vice-President, Officer of the Company.
Calgary, Alberta Marketing
Canada (age 58)
Real J. H. Doucet Senior Vice-President, Officer of the Company.
Calgary, Alberta Oil Sands
Canada (age 56)
Allen M. Knight Senior Vice-President, Officer of the Company.
Calgary, Alberta International & Corporate
Canada Development
(age 59)
Tim S. McKay Senior Vice-President, Officer of the Company.
Calgary, Alberta Operations
Canada (age 47)
Canadian Natural Resources Limited 54
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
Douglas A. Proll Chief Financial Officer Officer of the Company.
Calgary, Alberta and Senior Vice-President,
Canada Finance
(age 58)
Lyle G. Stevens Senior Vice-President, Officer of the Company.
Calgary, Alberta Exploitation
Canada (age 54)
Jeffrey W. Wilson Senior Vice-President, Officer of the Company.
Calgary, Alberta Exploration
Canada (age 56)
Jeffrey J. Bergeson Vice-President, Officer of the Company since May 2007; prior thereto
Calgary, Alberta Exploitation West Exploitation Manager of the Company.
Canada (age 52)
Corey B. Bieber Vice-President, Finance Officer of the Company since April 2005; prior thereto
Calgary, Alberta and Investor Relations Director, Investor Relations of the Company from July
Canada (age 45) 2002 to April 2005 and most recently Vice-President,
Investor Relations April 2005 to February 2007.
Mary-Jo E. Case Vice-President, Officer of the Company.
Calgary, Alberta Land
Canada (age 50)
William R. Clapperton Vice-President, Officer of the Company.
Calgary, Alberta Regulatory, Stakeholder
Canada and Environmental Affairs
(age 46)
James F. Corson Vice-President, Officer of the Company since January 2007; prior thereto
Calgary, Alberta Human Resources, Horizon Vice-President, Human Resources of Qatar Petroleum Corp.
Canada (age 58) from March 1997 to July 2005 and most recently Director
Human Resources and Stakeholder Relations of the Company
from July 2005 to 2007.
Randall S. Davis Vice-President, Officer of the Company since July 2004; prior thereto
Calgary, Alberta Finance & Accounting Financial Controller of the Company from July 2002 to
Canada (age 42) July 2004 and most recently Vice-President Financial
Accounting and Controls July 2004 to February 2007.
Allan E. 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 52) November 1998 to March 2005, Manager Facilities &
Construction for Anadarko Canada Corporation from April
2005 to November 2006, and most recently Production
Manager, Edson of the Company from November 2006 to March
2007.
Peter J. Janson Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Engineering Integration Director, Engineering Integration of the Company from
Canada (age 51) November 2002 to December 2004.
Philip A. Keele Vice-President, Officer of the Company since December 2004; prior thereto
Calgary, Alberta Mining, Director, Mine Engineering of the Company from September
Canada Horizon Oil Sands Project 2002 to December 2004.
(age 49)
55 Canadian Natural Resources Limited
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
Cameron S. Kramer Vice-President, Officer of the Company.
Calgary, Alberta Development Operations
Canada (age 41)
Ronald K. Laing Vice-President, Commercial Officer of the Company since March 2009; prior thereto
Calgary, Alberta Operations Commercial Operations Advisor of the Company from
Canada (age 39) November 2003 to April 2004, and most recently Manager,
Commercial Operations of the Company from April 2004 to
March 2009.
Leon Miura Vice-President, Officer of the Company.
Calgary, Alberta Horizon Major Projects
Canada (age 54)
Reno G. Laseur Vice-President, Officer of the Company since August 2008; prior thereto
Fort McMurray, Alberta Upgrading Operations Manager, Upgrading of the Company November
Canada (age 53) 2002 to October 2007, and most recently Operations
Director, Upgrading of the Company from October 2007 to
August 2008.
S. John Parr Vice-President, Officer of the Company since April 2004; prior thereto
Calgary, Alberta Production, East Production Manager, Heavy Oil of th e Company from July
Canada (age 47) 2002 to April 2004.
David A. Payne Vice-President, Officer of the Company since October 2004; prior thereto
Calgary, Alberta Exploitation, Central Exploitation Manager, Technical Projects of the Company
Canada (age 47) from August 2003 to October 2004, Vice-President,
Exploitation, West from October 2004 to April 2007, and
most recently Vice-President, Exploitation, East from May
2007 to February 2008.
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 42)
Timothy G. Reed Vice-President, Officer of the Company since January 2007; prior thereto
Calgary, Alberta Human Resources Manager, Human Resources of the Company 2000 to 2005 and
Canada (age 52) most recently Director, Human Resources 2005 to January
2007.
Joy P. Romero Vice President, Officer of the Company since March 2008; prior thereto
Calgary, Alberta Bitumen Production Director, Bitumen Production Process of the Company from
Canada (age 52) September 2002 to March 2008.
Sheldon L. Schroeder Vice-President, Officer of the Company since April 2004; prior thereto
Fort McMurray, Alberta Project Control Director, Project Control of the Company from September
Canada (age 41) 2002 to April 2004.
Kendall W. Stagg Vice-President, Officer of the Company since October 2004; prior thereto
Calgary, Alberta Exploration, West Manager Exploration, B. C. of the Company from June 2002
Canada (age 47) to September 2004.
Scott G. Stauth Vice-President, Officer of the Company since November 2006; prior thereto
Calgary, Alberta Field Operations Manager, Eastern Field Operations of the Company April
Canada (age 51) 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 49)
Canadian Natural Resources Limited 56
NAME POSITION PRESENTLY HELD PRINCIPAL OCCUPATION DURING PAST 5 YEARS
--------------------------------------------------------------------------------------------------------------------
Domenic Torriero Vice-President, Officer of the Company since November 2006; prior thereto
Calgary, Alberta Exploration, Central Vice-President Geology and Geophysics of Petrovera
Canada (age 44) Resources Limited January 1999 to March 2004 and most
recently Exploration Manager of the Company March 2004 to
November 2006.
Grant M. Williams Vice-President, Officer of the Company since March 2007; prior thereto
Calgary, Alberta Exploration, East Manager, Exploration Heavy Oil of the Company October
Canada (age 51) 2003 to April 2007.
Daryl G. Youck Vice-President, Officer of the Company since February 2008; prior thereto
Calgary, Alberta Exploitation, East Manager, Exploitation of the Company July 2002 to
Canada (age 40) February 2008.
Lynn M. Zeidler Vice-President, Officer of the Company.
Calgary, Alberta Utilities and Services
Canada (age 52)
Bruce E. McGrath Corporate Secretary Officer of the Company.
Calgary, Alberta (age 59)
Canada
======================================================================================================================
(1) Member of the nominating and corporate governance committee
(2) member of the audit committee
(3) member of the reserves committee
(4) member of the compensation committee
(5) member of the health, safety, and environmental committee
All directors stand for election at each Annual General Meeting of Canadian
Natural shareholders. All of the current directors were elected to the Board at
the last annual general meeting of shareholders held on May 8, 2008.
As at December 31, 2008, the directors and officers of the Company, as a group,
beneficially owned or controlled or directed, directly or indirectly, in the
aggregate, approximately 4% of the total outstanding common shares
(approximately 6% after the exercise of options held by them pursuant to the
Company's stock option plan).
57 Canadian Natural Resources Limited
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. 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 is reasonably expected to materially affect the Company.
Canadian Natural Resources Limited 58
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 National Instrument 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.
AUDITOR SERVICE FEES
The Audit Committee of the Board of Directors in 2008 approved specified audit
and non-audit services to be performed by PricewaterhouseCoopers LLP ("PwC").
The services provided include: (i) the annual audit of the Corporation's
internal controls and December 31, 2008 consolidated financial statements
included in the Annual Information Form and Form 40-F, reviews of the
Corporation's quarterly unaudited 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 including debt covenant
compliance and 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.
Fees accrued to PwC are shown in the table below.
|--------------|
Auditor service | 2008 | 2007
------------------------------------------------|--------------|---------------
Audit fees | $ 2,685,800 | $ 2,729,315
Audit related fees | 156,300 | 164,000
Tax related fees | 91,500 | 154,459
All other fees | 9,500 | 9,440
------------------------------------------------|--------------|---------------
| $ 2,943,100 | $ 3,057,214
================================================|==============|===============
The Charter of the Audit Committee of the Company is attached as Schedule "C"
to this Annual Information Form.
59 Canadian Natural Resources Limited
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
The Company's auditors are PricewaterhouseCoopers LLP, Chartered Accountants,
who have prepared an independent auditors' report dated March 4, 2009 in
respect of the Company's consolidated financial statements with accompanying
notes as at and for the three years ended December 31, 2008 and the Company's
internal control over financial reporting as at December 31, 2008.
PricewaterhouseCoopers LLP has advised that they are independent with respect
to the Company within the meaning of the Rules of Professional Conduct of the
Institute of Chartered Accountants of Alberta and the rules of the US
Securities and Exchange Commission.
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 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 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, Director nominees standing for re-election,
principal holders of the Company's securities, options to purchase the
Company's securities and interest of insiders in material transactions is
contained in the Company's Notice of Annual General Meeting and Information
Circular dated March 18, 2009 in connection with the Annual General Meeting of
Shareholders of Canadian Natural to be held on May 7, 2009 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,
2008 found on pages 40 to 73, 74 to 100 and 101 to 105 respectively, of the
2008 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
Canadian Natural Resources Limited 60
SCHEDULE "A"
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, 2008.
The reserves data consist of the following:
(a) (i) proved conventional crude oil, NGLs and natural gas reserve
quantities estimated as at December 31, 2008 using constant
prices and costs;
(ii) the related future net revenue; and
(iii) the related standardized measure calculation for proved
conventional crude oil, NGL and natural gas reserve quantities.
(b) (i) both proved, and proved and probable conventional crude oil,NGL
and natural gas reserve quantities estimated as at December 31,
2008 using forecast prices and costs;
(ii) the related future net revenue; and,
(c) (i) both proved, and proved and probable synthetic crude oil
reserves and associated bitumen quantities relating to surface
mineable oil sands operations estimated as at December 31, 2008.
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.
We carried out our evaluation in accordance with standards set out in the
Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared
jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter)
and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum
Society) with the necessary modifications to reflect definitions and
standards under the U.S. Financial Accounting Standards Board policies
(the "FASB Standards") and the legal requirements of the U.S. Securities
and Exchange Commission ("SEC Requirements").
3. 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 in the
COGE Handbook, the FASB Standards and the SEC Requirements.
61 Canadian Natural Resources Limited
4. The following table sets forth the estimated future net revenue (before
deduction of income taxes) attributed to proved plus probable reserves,
estimated using forecast prices and costs and calculated using a discount
rate of 10 percent, included in the reserves data of the Corporation
evaluated by us for the year ended December 31, 2008 and identifies the
respective portions thereof that we have evaluated and reported on to the
Corporation's management and board of directors:
------------------------------------------------------------------------------------------------------------------------------
INDEPENDENT
QUALIFIED
RESERVES DESCRIPTION AND LOCATION OF RESERVES NET PRESENT VALUE OF FUTURE NET REVENUE
EVALUATOR OR PREPARATION DATE OF (COUNTRY OR FOREIGN (BEFORE INCOME TAXES, 10% DISCOUNT RATE)
AUDITOR EVALUATION REPORT GEOGRAPHIC AREA) ($MILLIONS)
------------------------------------------------------------------------------------------------------------------------------
AUDITED EVALUATED REVIEWED TOTAL
------------------------------------------------------------------------------------------------------------------------------
Sproule Sproule Evaluated the P&NG Canada and USA $ 0 $ 40,841 $ 0 $ 40,841
Associates Reserves as reported February
Limited 17th, 2009.
------------------------------------------------------------------------------------------------------------------------------
Sproule Sproule Evaluated the P&NG United Kingdom and $ 0 $ 11,929 $ 0 $ 11,929
Associates Reserves as reported February
Limited 17th, 2009. Offshore West Africa
------------------------------------------------------------------------------------------------------------------------------
TOTALS $ 0 $ 52,770 $ 0 $ 52,770
==============================================================================================================================
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, 2008. GLJ Petroleum
Consultants ("GLJ"), an independent qualified reserves evaluator, was
retained by the Reserves Committee of Canadian Natural's Board of
Directors to evaluate reserves associated with the Horizon Project
incorporating both the mining and upgrading projects. These reserves were
evaluated under SEC Industry Guide 7 and are disclosed separately from the
Corporation's conventional crude oil and natural gas activities.
5. 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.
6. We have no responsibility to update our reports referred to in paragraph 4
for events and circumstances occurring after their respective preparation
dates.
7. Because the reserves data are based on judgements regarding future events,
actual results will vary and the variations may be material. However, any
variations should be consistent with the fact that reserves are
categorized according to the probability of their recovery.
Canadian Natural Resources Limited 62
Executed as to our report referred to above:
SPROULE ASSOCIATES LIMITED, CALGARY, ALBERTA, CANADA, FEBRUARY 25, 2009
Original Signed By:
--------------------------
Harry J. Helwerda, P.Eng.,
Executive Vice-President
Original Signed By:
--------------------------
Doug Ho, P.Eng.
Vice-President, Unconventional
Original Signed By:
--------------------------
R. Keith MacLeod, P.Eng. President
GLJ PETROLEUM CONSULTANTS, CALGARY, ALBERTA, CANADA, FEBRUARY 24, 2009
Original Signed By:
-------------------------
James H. Willmon, P.Eng.
Vice-President
63 Canadian Natural Resources Limited
SCHEDULE "B"
REPORT OF
MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE
REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
Management of Canadian Natural Resources Limited (the "Corporation") is
responsible for the preparation and disclosure of information with respect to
the Corporation's oil, 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, 2008 using constant prices
and costs;
(ii) the related future net revenue; and
(iii) the related standardized measure calculation for proved conventional
crude oil, NGL and natural gas reserve quantities.
(b) (i) both proved, and proved and probable conventional crude oil, NGL
and natural gas reserve quantities estimated as at December 31, 2008
using forecast prices and costs;
(ii) the related future net revenue; and,
(c) (i) both proved, and proved and probable synthetic crude oil reserves
and associated bitumen quantities relating to surface mineable oil
sands operations estimated as at December 31, 2008.
Sproule Associates Limited and GLJ Petroleum Consultants, both 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 evaluator;
(b) met with each of the independent qualified reserves evaluators to
determine whether any restrictions affected the ability of the independent
qualified reserves evaluators to report without reservation and in the
event of a proposal to change the independent qualified reserves
evaluators, to inquire whether there had been disputes between the
previous independent qualified reserves evaluators and management; 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 oil,
gas and surface mineable oil sands activities and has reviewed that information
with management. The Board of Directors has, on the recommendation of the
Reserves Committee, approved:
(a) the content and filing with securities regulatory authorities of Form
51-101F1 containing reserves data and other oil, gas and surface mineable
oil sands information;
(b) the filing of Form 51-101F2 which is the report of the independent
qualified reserves evaluators on the reserves data; and
(c) the content and filing of this report.
Because the reserves data are based on judgments regarding future events,
actual results will vary and the variations may be material. However, any
variations should be consistent with the fact that reserves are categorized
according to the probability of their recovery.
Canadian Natural Resources Limited 64
Original Signed By:
/s/ Steve W. Laut
--------------------------
Steve W. Laut
President and Chief Operating Officer
Original Signed By:
/s/ Douglas A. Proll
------------------------
Douglas A. Proll
Chief Financial Officer and Senior Vice President, Finance
Original Signed By:
/s/ David A. Tuer
--------------------------
David A. Tuer
Independent Director and Chair of the Reserve Committee
Original Signed By:
/s/ Norman F. McIntyre
--------------------------
Norman F. McIntyre
Independent Director and Member of the Reserve Committee
Dated this 3rd day of March, 2009
Calgary, Alberta
65 Canadian Natural Resources Limited
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. Although the Audit Committee has the powers and
responsibilities set forth in this Charter, the role of the Audit
Committee is oversight. The Audit Committee's primary duties and
responsibilities are to:
1. ensure that the Corporation's management implemented an effective
system of internal controls over financial reporting;
2. monitor and oversee 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, qualifications and performance of the
Corporation's independent auditors and oversee the audit of the
Corporation's financial statements;
5. monitor the performance of the internal audit 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 "financial expert" or similar designation
in accordance with the requirements of the regulatory bodies to which
the Corporation may be subject to.
Canadian Natural Resources Limited 66
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;
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 implemented
and is maintaining an effective system of internal controls over
financial reporting;
d. to report regularly to the Board on the fulfillment of its
duties and responsibilities; and,
67 Canadian Natural Resources Limited
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 review and discuss with management and the independent
auditors prior to the annual audit the independent auditor's
annual audit plan, including scope, staffing, locations and
reliance upon management and internal audit department and
oversee the audit of the Corporation's financial statements;
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 :
(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.
Canadian Natural Resources Limited 68
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.
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 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 (including financial reporting) and risk
management;
b. to review any unresolved issues between management and the
independent auditors that could affect the financial reporting
or internal controls of the Corporation; and
c. to periodically review 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 and discuss with management, the internal audit group
and the independent auditors, 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 and discuss with management, the internal audit group
and the independent auditors, 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;
69 Canadian Natural Resources Limited
d. to review management's report on 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 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.
Canadian Natural Resources Limited 70
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M A N A G E M E N T S ' S D I S C U S S I O N A N D A N A L Y S I S
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SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS
Certain statements in this document or documents results, performance or achievements expressed or implied
incorporated herein by reference constitute by such forward-looking statements. Such factors include,
forward-looking statements or information (collectively among others: general economic and business conditions
referred to herein as "forward-looking statements") which will, among other things, impact demand for and
within the meaning of applicable securities market prices of the Company's products; volatility of and
legislation. Forward-looking statements can be assumptions regarding crude oil and natural gas prices;
identified by the words "believe", "anticipate", fluctuations in currency and interest rates; assumptions on
"expect", "plan", "estimate", "target", "continue", which the Company's current guidance is based; economic
"could", "intend", "may", "potential", "predict", conditions in the countries and regions in which the
"should", "will", "objective", "project", "forecast", Company conducts business; political uncertainty, including
"goal", "guidance", "outlook", "effort", "seeks", actions of or against terrorists, insurgent groups or other
"schedule" or expressions of a similar nature conflict including conflict between states; industry
suggesting future outcome or statements regarding an capacity; ability of the Company to implement its business
outlook. Disclosure related to expected future strategy, including exploration and development activities;
commodity pricing, production volumes, royalties, impact of competition; the Company's defense of lawsuits;
operating costs, capital expenditures, and other availability and cost of seismic, drilling and other
guidance provided throughout this Management's equipment; ability of the Company and its subsidiaries to
Discussion and Analysis ("MD&A") including the complete capital programs; the Company's and its
information in the "outlook" section and the subsidiaries' ability to secure adequate transportation for
sensitivity analysis constitute forward-looking its products; unexpected difficulties in mining, extracting
statements. Disclosure of plans relating to existing or upgrading the Company's bitumen products; potential
and future developments, including but not limited to delays or changes in plans with respect to exploration or
the Horizon Project, Primrose East, Pelican Lake, Gabon development projects or capital expenditures; ability of
Offshore West Africa, and the Kirby Oil Sands Project the Company to attract the necessary labour required to
also constitute forward-looking statements. This build its thermal and oil sands mining projects; operating
forward-looking information is based on annual budgets hazards and other difficulties inherent in the exploration
and multi-year forecasts, and is reviewed and revised for and production and sale of crude oil and natural gas;
throughout the year if necessary in the context of availability and cost of financing; the Company's and its
targeted financial ratios, project returns, product subsidiaries' success of exploration and development
pricing expectations and balance in project risk and activities and their ability to replace and expand crude
time horizons. These statements are not guarantees of oil and natural gas reserves; timing and success of
future performance and are subject to certain risks and integrating the business and operations of acquired
the reader should not place undue reliance on these companies; production levels; imprecision of reserve
forward-looking statements as there can be no estimates and estimates of recoverable quantities of crude
assurances that the plans, initiatives or expectations oil, bitumen, natural gas and liquids not currently
upon which they are based will occur. classified as proved; actions by governmental authorities;
government regulations and the expenditures required to
In addition, statements relating to "reserves" are comply with them (especially safety and environmental laws
deemed to be forward-looking statements as they involve and regulations and the impact of climate change
the implied assessment based on certain estimates and initiatives on capital and operating costs); asset
assumptions that the reserves described can be retirement obligations; the adequacy of the Company's
profitably produced in the future. There are numerous provision for taxes; and other circumstances affecting
uncertainties inherent in estimating quantities of revenues and expenses. The Company's operations have been,
proved crude oil and natural gas reserves and in and in the future may be, affected by political
projecting future rates of production and the timing of developments and by federal, provincial and local laws and
development expenditures. The total amount or timing of regulations such as restrictions on production, changes in
actual future production may vary significantly from taxes, royalties and other amounts payable to governments
reserve and production estimates. or governmental agencies, price or gathering rate controls
and environmental protection regulations. Should one or
The forward-looking statements are based on current more of these risks or uncertainties materialize, or should
expectations, estimates and projections about Canadian any of the Company's assumptions prove incorrect, actual
Natural Resources Limited (the "Company") and the results may vary in material respects from those projected
industry in which the Company operates, which speak in the forward-looking statements. The impact of any one
only as of the date such statements were made or as of factor on a particular forward-looking statement is not
the date of the report or document in which they are determinable with certainty as such factors are dependent
contained, and are subject to known and unknown risks, upon other factors, and the Company's course of action
uncertainties and other factors that could cause the would depend upon its assessment of the future considering
actual results, performance or achievements of the all information then available. For additional information
Company to be materially different from any future refer to the "Risks and Uncertainties" section of this
MD&A.
40 CANADIAN NATURAL
Readers are cautioned that the foregoing list of oil to estimate relative energy content. This conversion
factors is not exhaustive. Unpredictable or unknown may be misleading, particularly when used in isolation,
factors not discussed in this report could also have since the 6 mcf:1 bbl ratio is based on an energy
material adverse effects on forward-looking statements. equivalency at the burner tip and does not represent the
Although the Company believes that the expectations value equivalency at the wellhead. Production volumes are
conveyed by the forward-looking statements are the Company's interest before royalties, and realized
reasonable based on information available to it on the prices are net of transportation and blending costs and
date such forward-looking statements are made, no exclude the effect of risk management activities. The
assurances can be given as to future results, levels of following discussion and analysis refers primarily to the
activity and achievements. All subsequent Company's 2008 financial results compared to 2007 and 2006,
forward-looking statements, whether written or oral, unless otherwise indicated. In addition, this MD&A details
attributable to the Company or persons acting on its the Company's capital program and outlook for 2009.
behalf are expressly qualified in their entirety by
these cautionary statements. Except as required by law, Additional information relating to the Company, including
the Company assumes no obligation to update its quarterly MD&A for the year and three months ended
forward-looking statements should circumstances or December 31, 2008 and its Annual Information Form for the
Management's estimates or opinions change. year ended December 31, 2008, is available on SEDAR at
www.sedar.com.
SPECIAL NOTE REGARDING
NON-GAAP FINANCIAL MEASURES This MD&A is dated March 4, 2009.
Management's Discussion and Analysis includes ABBREVIATIONS
references to financial measures commonly used in the
crude oil and natural gas industry, such as adjusted ACC .................Anadarko Canada Corporation
net earnings from operations, cash flow from operations AECO ................Alberta natural gas reference
and net asset value. These financial measures are not location
defined by generally accepted accounting principles in API .................Specific gravity measured in degrees
Canada ("GAAP") and therefore are referred to as on the American Petroleum Institute
non-GAAP measures. The non-GAAP measures used by the scale
Company may not be comparable to similar measures ARO .................Asset retirement obligations
presented by other companies. The Company uses these bbl .................barrels
non-GAAP measures to evaluate its performance. The bbl/d ...............barrels per day
non-GAAP measures should not be considered an bcf .................billion cubic feet
alternative to or more meaningful than net earnings, as boe .................barrels of oil equivalent
determined in accordance with Canadian GAAP, as an boe/d ...............barrels of oil equivalent per day
indication of the Company's performance. The non-GAAP Brent ...............Dated Brent
measures adjusted net earnings from operations and cash C$ ..................Canadian dollars
flow from operations are reconciled to net earnings, as CICA ................Canadian Institute of Chartered
determined in accordance with Canadian GAAP, in the Accountants
"Financial Highlights" section of this MD&A. The CO2 .................Carbon dioxide
Company also presents certain non-GAAP financial ratios CO2e ................Carbon dioxide equivalents
and their derivation in the "Liquidity and Capital Canadian GAAP .......Generally accepted accounting
Resources" section of this MD&A. principles in Canada
FPSO ................Floating Production, Storage and
MANAGEMENT'S DISCUSSION AND ANALYSIS Offtake Vessel
GHG .................Greenhouse Gas
Management's Discussion and Analysis of the financial GJ ..................gigajoules
condition and results of operations of the Company GJ/d ................gigajoules per day
should be read in conjunction with the Company's Heavy
audited consolidated financial statements and related Differential ........Heavy crude oil differential from
notes for the year ended December 31, 2008. The WTI
consolidated financial statements have been prepared in Horizon Project .....Horizon Oil Sands Project
accordance with generally accepted accounting LIBOR ...............London Interbank Offered Rate
principles in Canada ("Canadian GAAP"). A mcf .................thousand cubic feet
reconciliation of Canadian GAAP to generally accepted mmbbl ...............million barrels
accounting principles in the United States ("US GAAP") mmbtu ...............million British thermal units
is included in note 18 to the consolidated financial mmcf/d ..............million cubic feet per day
statements. All dollar amounts are referenced in NGLs ................Natural gas liquids
Canadian dollars, except where otherwise noted. The NYMEX ...............New York Mercantile Exchange
calculation of barrels of oil equivalent ("boe") is NYSE ................New York Stock Exchange
based on a conversion ratio of six thousand cubic feet PRT .................Petroleum Revenue Tax
("mcf") of natural gas to one barrel ("bbl") of crude SCO .................Synthetic light crude oil
SEC .................United States Securities and
Exchange Commission
TSX .................Toronto Stock Exchange
UK ..................United Kingdom
US ..................United States
US GAAP .............Generally accepted accounting
principles in the United States
US$ .................United States dollars
WCS .................Western Canadian Select
WTI .................West Texas Intermediate
CANADIAN NATURAL 41
OBJECTIVE AND STRATEGY
The Company's objectives are 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/or acquisition of new
reserves. The Company strives to meet these objectives 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 value. 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 and terms of debt financing and maintenance
of a strong balance sheet.
(1) discounted value of conventional crude oil and natural gas
reserves plus value of undeveloped land, less net debt.
(2) Pelican Lake crude oil is 14-17(0) API oil, which receives
medium quality crude netbacks due to lower production costs
and lower 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 and/or new
additions; and
o Supporting and participating in projects that will increase the
downstream conversion capacity for heavy crude oil.
Operational discipline and cost control are fundamental to the Company.
By consistently controlling costs throughout all cycles of the industry,
the Company believes it will achieve continued growth. Cost control is
attained by developing area knowledge, by dominating core areas and by
maintaining high working interests and operator status in its properties.
The Company is committed to maintaining a strong balance sheet and
flexible capital structure. The Company believes it has built the
necessary financial capacity to complete all of its growth projects,
including the Horizon Project and its conventional crude oil and natural
gas opportunities. Additionally, the Company's risk management hedge
program reduces the risk of volatility in commodity prices and supports
the Company's cash flow for its capital expenditures programs.
Strategic accretive acquisitions, like the acquisition of ACC in 2006,
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.
Highlights for the year ended December 31, 2008 include the following:
o Achieved record levels of net earnings, adjusted net earnings from
operations, and cash flow from operations;
o Achieved annual crude oil and natural gas production guidance;
o Completed the construction of and achieved first production from
the Primrose East Expansion;
o Completed drilling and brought three wells back on production at
the Baobab Field, Cote d'Ivoire;
o Development continued on the Olowi Field in offshore Gabon with
first oil targeted for Spring 2009;
o Substantially completed construction of Phase 1 of the Horizon
Project; and
o Increased dividends per common share.
NET EARNINGS AND CASH FLOW FROM OPERATIONS
Financial Highlights
($ millions, except per common share amounts) 2008| 2007 2006
---------------------------------------------------------------------------|-------------------------
Revenue, before royalties $ 16,173| $ 12,543 $ 11,643
Net earnings $ 4,985| $ 2,608 $ 2,524
Per common share - basic and diluted $ 9.22| $ 4.84 $ 4.70
Adjusted net earnings from operations(1) $ 3,492| $ 2,406 $ 1,664
Per common share - basic and diluted $ 6.46| $ 4.46 $ 3.10
Cash flow from operations (2) $ 6,969| $ 6,198 $ 4,932
Per common share - basic and diluted $ 12.89| $ 11.49 $ 9.18
Dividends declared per common share $ 0.40| $ 0.34 $ 0.30
Total assets $ 42,650| $ 36,114 $ 33,160
Total long-term liabilities $ 20,856| $ 19,230 $ 19,399
Capital expenditures, net of dispositions $ 7,451| $ 6,425 $ 12,025
===========================================================================|=========================
(1) Adjusted net earnings from operations is a non-GAAP measure 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 reconciliation
"Adjusted Net Earnings from Operations" presented below 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.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital
adjustments. 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. The reconciliation "Cash Flow
from Operations" presented below lists the effects of certain
non-cash items that are included in the Company's financial
results. Cash flow from operations may not be comparable to similar
measures presented by other companies.
42 CANADIAN NATURAL
Adjusted Net Earnings from Operations
($ millions) 2008 | 2007 2006
--------------------------------------------------------------------------|-----------------------
Net earnings as reported $ 4,985 | $ 2,608 $ 2,524
Stock-based compensation (recovery) expense, net of (38)| 134 95
tax(a) |
Unrealized risk management (gain) loss, net of tax(b) (2,112)| 977 (674)
Unrealized foreign exchange loss (gain), net of tax(c) 698 | (449) 114
Effect of statutory tax rate and other legislative (41)| (864) (395)
changes on future income tax liabilities(d) |
--------------------------------------------------------------------------|-----------------------
Adjusted net earnings from operations $ 3,492 | $ 2,406 $ 1,664
==================================================================================================
(a) The Company's employee stock option plan provides for a cash
payment option. Accordingly, the intrinsic value of outstanding
vested options is recorded as a liability on the Company's balance
sheet and periodic changes in the intrinsic value are recognized in
net earnings or are capitalized as part of the Horizon Project
during the construction period.
(b) Derivative financial instruments are recorded at fair value on the
balance sheet, with changes in fair value of non-designated hedges
recognized in 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, offset by the impact of cross currency
swap hedges, and are recognized in net earnings.
(d) All substantively enacted or enacted adjustments in applicable
income tax rates and other legislative changes 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 and other legislative
changes is recorded in net earnings during the period the
legislation is substantively enacted or enacted. Income tax rate
changes during 2008 resulted in a reduction of future income tax
liabilities of approximately $19 million in North America and $22
million in Cote d'Ivoire, Offshore West Africa. Income tax rate and
other legislative changes during 2007 resulted in a reduction of
future income tax liabilities of approximately $864 million in
North America. Income tax rate changes during 2006 resulted in an
increase of future income tax liabilities of approximately $110
million in the North Sea, a reduction of approximately $438 million
in North America, and a reduction of approximately $67 million in
Cote d'Ivoire, Offshore West Africa.
Cash Flow from Operations
($ millions) 2008 | 2007 2006
-----------------------------------------------------------------------|------------------------------
Net earnings $ 4,985 | $ 2,608 $ 2,524
Non-cash items: |
Depletion, depreciation and amortization 2,683 | 2,863 2,391
Asset retirement obligation accretion 71 | 70 68
Stock-based compensation (recovery) expense (52)| 193 139
Unrealized risk management (gain) loss (3,090)| 1,400 (1,013)
Unrealized foreign exchange loss (gain) 832 | (524) 134
Deferred petroleum revenue tax (recovery) |
expense (67)| 44 37
Future income tax expense (recovery) 1,607 | (456) 652
-----------------------------------------------------------------------|------------------------------
Cash flow from operations $ 6,969 | $ 6,198 $ 4,932
======================================================================================================
For 2008, the Company reported net earnings of $4,985 million compared to
net earnings of $2,608 million for 2007 (2006 - $2,524 million). Net
earnings for the year ended December 31, 2008 included net unrealized
after-tax income of $1,493 million related to the effects of risk
management activities, changes in foreign exchange rates, stock-based
compensation, and the impact of statutory tax rate and other legislative
changes on future income tax liabilities (2007 - $202 million; 2006 -
$860 million). Excluding these items, adjusted net earnings from
operations for the year ended December 31, 2008 increased to $3,492
million from $2,406 million for 2007 (2006 - $1,664 million) primarily
due to the impact of higher realized pricing, lower depletion,
depreciation and amortization expense, and lower interest and
administration expense. These factors were partially offset by higher
realized risk management losses, higher royalty and production expense,
lower sales volumes, and the impact of the stronger Canadian dollar
relative to the US dollar during the first half of 2008.
The impacts of unrealized risk management activities, stock-based
compensation and changes in foreign exchange rates are expected to
continue to contribute to significant volatility in consolidated net
earnings and are discussed in detail in the relevant sections of this
MD&A.
Cash flow from operations for the year ended December 31, 2008 increased
to $6,969 million ($12.89 per common share) from $6,198 million ($11.49
per common share) for 2007 (2006 - $4,932 million; $9.18 per common
share). The increase was primarily due to the impact of higher realized
pricing and lower interest and administration expense, partially offset
by higher realized risk management losses, higher royalty and production
expense, higher current income tax expense, lower sales volumes, and the
impact of the stronger Canadian dollar relative to the US dollar during
the first half of 2008.
For 2008, the Company's average sales price per bbl of crude oil and NGLs
increased to $82.41 per bbl from $55.45 per bbl in 2007 (2006 - $53.65
per bbl). The Company's average natural gas price increased to $8.39 per
mcf from $6.85 per mcf for 2007 (2006 - $6.72 per mcf).
Total production of crude oil and NGLs before royalties decreased to
315,667 bbl/d from 331,232 bbl/d for 2007 (2006 - 331,998 bbl/d). The
decrease in crude oil and NGLs production was primarily due to lower
production in the North Sea and Offshore West Africa due to the timing of
field turnarounds, the sale of the Company's working interest in the
B-Block Fields late in 2007, and the impact of the shut in of a portion
of the Baobab Field production, and in North America due to the cyclic
nature of the Company's thermal production.
CANADIAN NATURAL 43
Total natural gas production before royalties decreased to 1,495 mmcf/d
from 1,668 mmcf/d for 2007 (2006 - 1,492 mmcf/d). The decrease in natural
gas production primarily reflected natural production declines due to the
Company's strategic reduction in natural gas drilling activity in North
America.
Total crude oil and NGLs and natural gas production volumes before
royalties decreased to 564,845 boe/d from 609,206 boe/d for 2007 (2006 -
580,724 boe/d). Total production for 2008 was within the Company's
previously issued guidance.
Operating highlights
2008| 2007 2006
---------------------------------------------------|---------------------------
Crude oil and NGLs ($/bbl)(1) |
Sales price(2) $ 82.41| $ 55.45 $ 53.65
Royalties 10.48| 5.94 4.48
Production expense 16.26| 13.34 12.29
---------------------------------------------------|---------------------------
Netback $ 55.67| $ 36.17 $ 36.88
---------------------------------------------------|---------------------------
Natural gas ($/mcf)(1) |
Sales price(2) $ 8.39| $ 6.85 $ 6.72
Royalties 1.46| 1.11 1.29
Production expense 1.02| 0.91 0.82
---------------------------------------------------|---------------------------
Netback $ 5.91| $ 4.83 $ 4.61
---------------------------------------------------|---------------------------
Barrels of oil equivalent ($/boe)(1) |
Sales price(2) $ 68.62| $ 49.05 $ 47.92
Royalties 9.78| 6.26 5.89
Production expense 11.79| 9.75 9.14
---------------------------------------------------|---------------------------
Netback $ 47.05| $ 33.04 $ 32.89
===============================================================================
(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
eight most recently completed quarters:
($ millions, except per common share amounts)
2008 Total Dec 31 Sep 30 Jun 30 Mar 31
------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 16,173 $ 2,511 $ 4,583 $ 5,112 $ 3,967
Net earnings (loss) $ 4,985 $ 1,770 $ 2,835 $ (347) $ 727
Net earnings (loss) per common
share
- basic and diluted $ 9.22 $ 3.27 $ 5.25 $ (0.65) $ 1.35
------------------------------------------------------------------------------------------------------------
2007 Total Dec 31 Sep 30 Jun 30 Mar 31
------------------------------------------------------------------------------------------------------------
Revenue, before royalties $ 12,543 $ 3,200 $ 3,073 $ 3,152 $ 3,118
Net earnings $ 2,608 $ 798 $ 700 $ 841 $ 269
Net earnings per common share
- basic and diluted $ 4.84 $ 1.48 $ 1.30 $ 1.56 $ 0.50
=============================================================================================================
Net earnings (loss) over the eight most recently completed quarters
generally reflected fluctuations in realized crude oil and natural gas
prices, fluctuations in sales volumes, the impact of mark-to-market
accounting of derivative financial instruments and stock-based
compensation, fluctuations in depletion, depreciation and amortization
charges and foreign exchange rates, and adjustments to future income tax
liabilities due to statutory tax rate and other legislative changes. More
specifically, volatility in quarterly net earnings was primarily due to:
o Crude oil pricing
Crude oil prices reflected fluctuating demand, geopolitical
uncertainties and fluctuations in the Heavy Differential in North
America.
o Natural gas pricing
Natural gas prices primarily reflected seasonal fluctuations in
both the demand for natural gas and inventory storage levels,
fluctuations in liquefied natural gas imports into the US, and
increased shale gas production in the US.
o Crude oil and NGLs sales volumes
Crude oil and NGLs sales volumes primarily reflected increased
production from the Company's Primrose thermal projects, the
results from the Pelican Lake water and polymer flood projects, and
development of the Espoir Field. Crude oil and NGLs sales volumes
also reflected fluctuations in production from the North Sea and
Offshore West Africa due to timing of liftings and maintenance
activities and the impact of the shut in of a portion of the Baobab
Field production.
44 CANADIAN NATURAL
o Natural gas sales volumes
Natural gas sales volumes primarily reflected production declines
due to the Company's strategic decision to reduce natural gas
drilling activity in North America due to the allocation of capital
to higher return crude oil projects, as well as natural decline
rates.
o Foreign exchange rates
Fluctuations in the Canadian dollar relative to the US dollar
impacted the realized price the Company received for its crude oil
and natural gas sales, as sales prices are based predominately on
US dollar denominated benchmarks. Similarly, unrealized foreign
exchange gains and losses were recorded with respect to US dollar
denominated debt and the re-measurement of North Sea future income
tax liabilities denominated in UK pounds sterling to US dollars,
partially offset by the impact of cross currency swap hedges.
o Risk management
Net earnings (loss) have fluctuated due to the recognition of
realized and unrealized gains and losses from the mark-to-market
and subsequent settlement of the Company's risk management
activities.
o Changes in income tax expense
Fluctuations in income tax expense (recovery) include statutory tax
rate and other legislative changes substantively enacted or enacted
in the various periods.
o Stock-based compensation
Net earnings (loss) have fluctuated due to the mark-to-market
movements of the Company's stock-based compensation liability.
Stock-based compensation expense (recovery) reflected fluctuations
in the Company's share price over the eight most recently completed
quarters.
o Production expense
Production expense has fluctuated company wide primarily due to the
impact of the demand for services, industry-wide inflationary cost
pressures experienced in prior quarters in all segments,
fluctuations in product mix, and the impact of seasonal costs that
are dependent on weather.
o Depletion, depreciation and amortization
Depletion, depreciation and amortization expense has fluctuated due
to changes in sales volumes, finding and development costs
associated with crude oil and natural gas exploration, and
estimated future costs to develop the Company's proved undeveloped
reserves.
BUSINESS ENVIRONMENT
(Yearly average) 2008 | 2007 2006
---------------------------------------------------------------|--------------------------------------
WTI benchmark price (US$/bbl) $ 99.65 | $ 72.40 $ 66.25
Dated Brent benchmark price (US$/bbl) $ 96.99 | $ 72.59 $ 65.18
WCS blend differential from WTI |
(US$/bbl)(1) $ 20.03 | $ 23.25 $ 21.53
WCS blend differential from WTI (%)(1) 20%| 32% 32%
Condensate benchmark price (US$/bbl) $ 100.10 | $ 72.88 $ 66.24
NYMEX benchmark price (US$/mmbtu) $ 8.95 | $ 6.92 $ 7.26
AECO benchmark price (C$/GJ) $ 7.71 | $ 6.26 $ 6.62
US / Canadian dollar average exchange rate $ 0.9381 | $ 0.9304 $ 0.8818
US / Canadian dollar year end exchange rate $ 0.8166 | $ 1.0120 $ 0.8581
======================================================================================================
(1) Beginning in 2008, the Company has quantified the Heavy
Differential using the WCS blend as the heavy crude oil marker.
Prior period amounts have been reclassified.
Commodity Prices
Substantially all of the Company's production is sold based on US dollar
benchmark pricing. Specifically, crude oil is marketed based on WTI and
Brent indices. Canadian natural gas pricing is primarily based on Alberta
AECO reference pricing, which is derived from the NYMEX reference pricing
and adjusted for its basis or location differential to the NYMEX delivery
point at Henry Hub. The Company's realized price is also highly sensitive
to fluctuations in foreign exchange rates. The average value of the
Canadian dollar in relation to the US dollar fluctuated significantly
throughout 2008, with a high of approximately $1.03 in February 2008 and
a low of approximately $0.77 in December 2008.
The overall increase in WTI pricing in 2008 reflected strong demand for
crude oil and tight supply during the first half of 2008, followed by a
significant decrease in demand as a result of worldwide financial and
economic events during the fourth quarter of the year. WTI pricing was
also impacted by ongoing geopolitical uncertainty resulting in increased
market volatility. For 2008, WTI averaged US$99.65 per bbl, an increase
of 38% compared to US$72.40 per bbl for 2007 (2006 - US$66.25 per bbl).
WTI reached a high of US$147.27 per bbl on July 11, 2008 and a low of
US$32.40 per bbl on December 19, 2008.
Brent averaged US$96.99 per bbl for 2008, an increase of 34% compared to
US$72.59 per bbl for 2007 (2006 - US$65.18 per bbl). Crude oil sales
contracts for the North Sea and Offshore West Africa are typically based
on Brent pricing, which was also impacted by worldwide financial and
economic events late in the year.
CANADIAN NATURAL 45
The Company's realized crude oil prices benefited from strong commodity
pricing during most of the year and a favorable Heavy Differential. The
Heavy Differential averaged 20% of WTI for 2008, compared to 32% for 2007
(2006 - 32%). As the worldwide demand for diesel remained strong and the
refinery cracking margins were relatively weak, the Heavy Differential
continued to remain strong, despite the falling benchmark pricing late in
2008.
The Company anticipates continued volatility in the crude oil pricing
benchmarks due to the unpredictable nature of supply and demand factors,
geopolitical events and the global economic slowdown resulting from
worldwide financial and economic events. The Heavy Differential is
expected to continue to reflect seasonal demand fluctuations and refinery
cracking margins.
NYMEX natural gas prices averaged US$8.95 per mmbtu for 2008, an increase
of 29% from US$6.92 per mmbtu for 2007 (2006 - US$7.26 per mmbtu). The
Alberta based AECO natural gas pricing for 2008 increased 23% to average
$7.71 per GJ from $6.26 per GJ in 2007 (2006 - $6.62 per GJ). During the
first half of 2008, the demand and pricing for natural gas were tracking
with oil pricing and general economic activity. During the second half of
the year, natural gas pricing decreased due to a significant increase in
production from shale gas reservoirs in the US and a significant decline
in industrial demand caused by the onset of worldwide financial and
economic events.
Operating, Royalty and Capital Costs
Strong commodity prices over the last several years have resulted in
increased demand for oilfield services worldwide. This has led to
inflationary operating and capital cost pressures throughout the crude
oil and natural gas industry, particularly related to drilling activities
and oil sands developments.
The crude oil and natural gas industry is also experiencing cost pressures
related to environmental regulations, both in North America and
internationally. In Canada, the Federal Government has indicated its intent
to develop regulations that would be in effect in 2010 to address
industrial GHG emissions; however future Federal regulatory requirements
remain uncertain. The Federal Government has also outlined national and
sectoral reduction targets for several categories of air pollutants. In
Alberta, GHG regulations came into effect July 1, 2007, affecting
facilities emitting more than 100 kilotonnes of CO2e annually. Two of the
Company's facilities, the Primrose/Wolf Lake in-situ heavy crude oil
facilities and the Hays sour natural gas plant, fall under the regulations.
Commencing July 1, 2008, the British Columbia carbon tax is being assessed
at $10/tonne of CO2e on fuel consumed in the province, increasing to
$30/tonne by July 1, 2012. In the UK, GHG regulations have been in effect
since 2005. During Phase 1 (2005 - 2007) of the UK National Allocation
Plan, the Company operated below its CO2 allocation. For Phase 2 (2008 -
2012) the Company's CO2 allocation has been decreased below the Company's
estimated current operations emissions. The Company continues to focus on
implementing reduction programs based on efficiency audits to reduce CO2
emissions at its major facilities and on trading mechanisms to ensure
compliance with requirements now in effect.
Continued cost pressures and the final outcome of changes to
environmental regulations may adversely impact the Company's future net
earnings, cash flow and capital projects. For additional details, refer
to the "Greenhouse Gas and Other Air Emissions" section of this MD&A.
The Alberta Government implemented its New Royalty Framework ("NRF")
effective January 1, 2009. The NRF includes a number of changes to
royalty rates for natural gas, conventional crude oil, and oil sands
production. Under the NRF, royalties payable vary according to commodity
prices and the productivity of wells. Leading up to the January 2009
implementation of the NRF, the Alberta Government made several
adjustments to the originally proposed formula to address unintended
consequences. These adjustments affect royalties payable for certain
natural gas and crude oil production wells. For additional details, refer
to the "Royalties" section of this MD&A.
46 CANADIAN NATURAL
ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES AND RISK MANAGEMENT ACTIVITIES
Changes due to Changes due to
---------------------------------------------------------------------------------------------------------------------------
($ millions) 2006 Volumes Prices Other 2007 Volumes Prices Other 2008
---------------------------------------------------------------------------------------------------------------------------
North America
Crude oil and $ 5,262 $ 298 $ 287 $ - $ 5,847 $ (49) $ 3,013 $ - $ 8,811
NGLs
Natural gas 3,804 452 46 - 4,302 (531) 914 - 4,685
---------------------------------------------------------------------------------------------------------------------------
9,066 750 333 - 10,149 (580) 3,927 - 13,496
---------------------------------------------------------------------------------------------------------------------------
North Sea
Crude oil and 1,600 (107) 82 - 1,575 (334) 512 - 1,753
NGLs
Natural gas 16 (2) 8 - 22 (5) (1) - 16
---------------------------------------------------------------------------------------------------------------------------
1,616 (109) 90 - 1,597 (339) 511 - 1,769
---------------------------------------------------------------------------------------------------------------------------
Offshore West
Africa
Crude oil and 931 (216) 36 - 751 (136) 280 - 895
NGLs
Natural gas 19 5 1 - 25 5 19 - 49
---------------------------------------------------------------------------------------------------------------------------
950 (211) 37 - 776 (131) 299 - 944
---------------------------------------------------------------------------------------------------------------------------
Subtotal
Crude oil and 7,793 (25) 405 - 8,173 (519) 3,805 - 11,459
NGLs
Natural gas 3,839 455 55 - 4,349 (531) 932 - 4,750
---------------------------------------------------------------------------------------------------------------------------
11,632 430 460 - 12,522 (1,050) 4,737 - 16,209
---------------------------------------------------------------------------------------------------------------------------
Midstream 72 - - 2 74 - - 3 77
Intersegment (61) - - 8 (53) - - (60) (113)
eliminations
and other(1)
---------------------------------------------------------------------------------------------------------------------------
Total $ 11,643 $ 430 $ 460 $ 10 $ 12,543 $ (1,050) $ 4,737 $ (57) $ 16,173
===========================================================================================================================
(1) Eliminates primarily internal transportation, electricity charges,
and natural gas sales.
Revenue increased 29% to $16,173 million for 2008 from $12,543 million for
2007 (2006 - $11,643 million). The increase was primarily due to increased
realized crude oil and NGLs and natural gas prices company-wide.
For 2008, 17% of the Company's crude oil and natural gas revenue was
generated outside of North America (2007 - 19%; 2006 - 22%). North Sea
accounted for 11% of crude oil and natural gas revenue for 2008 (2007 -
13%; 2006 - 14%), and Offshore West Africa accounted for 6% of crude oil
and natural gas revenue for 2008 (2007 - 6%; 2006 - 8%).
ANALYSIS OF PRODUCT PRICES
2008 | 2007 2006
-----------------------------------------------------------------|---------------------------------
Crude oil and NGLs ($/bbl) (1) (2) |
North America $ 77.42 | $ 49.16 $ 46.52
North Sea $ 100.31 | $ 74.99 $ 72.62
Offshore West Africa $ 97.96 | $ 71.68 $ 67.99
Company average $ 82.41 | $ 55.45 $ 53.65
Natural gas ($/mcf) (1) (2) |
-----------------------------------------------------------------|---------------------------------
North America $ 8.41 | $ 6.87 $ 6.77
North Sea $ 4.09 | $ 4.26 $ 2.66
Offshore West Africa $ 10.03 | $ 5.68 $ 5.37
Company average $ 8.39 | $ 6.85 $ 6.72
-----------------------------------------------------------------|---------------------------------
Company average ($/boe) (1) (2) $ 68.62 | $ 49.05 $ 47.92
-----------------------------------------------------------------|---------------------------------
Percentage of gross revenue (2) (excluding |
midstream revenue) |
Crude oil and NGLs 68% | 62% 64%
Natural gas 32% | 38% 36%
-----------------------------------------------------------------|---------------------------------
(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.
Realized crude oil and NGLs prices increased 49% to average $82.41 per
bbl for 2008 from $55.45 per bbl for 2007 (2006 - $53.65 per bbl). The
increase in 2008 was primarily a result of higher WTI and Brent benchmark
crude oil prices during most of the year and a narrower Heavy
Differential, partially offset by the impact of the stronger Canadian
dollar relative to the US dollar during the first half of 2008.
The Company's realized natural gas price increased 22% to average $8.39
per mcf for 2008 from $6.85 per mcf for 2007 (2006 - $6.72 per mcf). The
increase in 2008 was primarily a result of increased benchmark prices due
to increased industrial demand and lower liquefied natural gas imports
into the US in the first half of 2008, partially offset by a significant
reduction in industrial demand late in the year as a result of worldwide
financial and economic events, and the impact of higher storage levels
due to increased shale gas production in the US.
CANADIAN NATURAL 47
--------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
--------------------------------------------------------------------------------
North America
North America realized crude oil prices increased 57% to average $77.42
per bbl for 2008 from $49.16 per bbl for 2007 (2006 - $46.52 per bbl). The
increase in 2008 was due to increased WTI benchmark pricing and a narrower
Heavy Differential, partially offset by the impact of the strong Canadian
dollar during the first half of 2008.
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 2008, the Company contributed approximately
150,000 bbl/d of heavy crude oil blends to the WCS stream. The Company has
entered into a 20 year transportation agreement to commit to ship 120,000
bbl/d of heavy sour crude oil on the proposed 500,000 bbl/d Keystone
Pipeline US Gulf Coast expansion from Hardisty, Alberta to the US Gulf
Coast. Contemporaneously, the Company also entered into a 20 year crude
oil purchase and sales agreement to sell 100,000 bbl/d of heavy sour crude
oil to a major US refiner. Deliveries under the agreements are expected to
commence in 2012 upon completion of the pipeline expansion and are subject
to Keystone's receipt of regulatory approval of the pipeline expansion.
North America realized natural gas prices increased 22% to average $8.41
per mcf for 2008 from $6.87 per mcf for 2007 (2006 - $6.77 per mcf),
primarily related to fluctuations in benchmark prices due to the impact of
weather and storage levels.
Comparisons of the prices received for the Company's North America
production by product type were as follows:
2008| 2007 2006
---------------------------------------------------|----------------------------
|
Wellhead Price (1) (2) |
Light/medium crude oil |
and NGLs (C$/bbl) $ 89.04| $ 66.24 $ 63.09
Pelican Lake crude oil (C$/bbl) $ 76.91| $ 46.29 $ 45.02
Primary heavy crude oil (C$/bbl) $ 74.91| $ 43.77 $ 41.35
Thermal heavy crude oil (C$/bbl) $ 71.89| $ 43.49 $ 40.98
Natural gas (C$/mcf) $ 8.41| $ 6.87 $ 6.77
===================================================|============================
(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 Sea
North Sea realized crude oil prices increased 34% to average $100.31 per
bbl for 2008 from $74.99 per bbl for 2007 (2006 - $72.62 per bbl).
Realized crude oil prices per bbl in any particular period are dependant
on the terms of the various sales contracts, the frequency and timing of
liftings of each field, and prevailing crude oil prices at the time of
lifting. Realized crude oil prices in the North Sea during 2008 benefited
from the increased Brent benchmark pricing, partially offset by the impact
of the strong Canadian dollar during the first half of 2008.
Offshore West Africa
Offshore West Africa realized crude oil prices increased 37% to average
$97.96 per bbl for 2008 from $71.68 per bbl for 2007 (2006 - $67.99 per
bbl). Realized crude oil prices per bbl in any particular period are
dependant on the terms of the various sales contracts, the frequency and
timing of liftings of each field, and prevailing crude oil prices at the
time of lifting. Realized crude oil prices in Offshore West Africa during
2008 benefited from the increased Brent benchmark pricing, partially
offset by the impact of the strong Canadian dollar during the first half
of 2008.
ANALYSIS OF DAILY PRODUCTION PRODUCTION, BEFORE ROYALTIES
2008 | 2007 2006
------------------------------------------------|--------------------------
Crude oil and NGLs (bbl/d) |
North America 243,826 | 246,779 235,253
North Sea 45,274 | 55,933 60,056
Offshore West Africa 26,567 | 28,520 36,689
------------------------------------------------|--------------------------
315,667 | 331,232 331,998
----------------------------------------------- |--------------------------
Natural gas (mmcf/d) |
North America 1,472 | 1,643 1,468
North Sea 10 | 13 15
Offshore West Africa 13 | 12 9
------------------------------------------------|--------------------------
1,495 | 1,668 1,492
------------------------------------------------|--------------------------
Total barrels of oil |
equivalent (boe/d) 564,845 | 609,206 580,724
------------------------------------------------|--------------------------
Product mix
Light/medium crude oil and NGLs 22%| 23% 26%
Pelican Lake crude oil 6%| 6% 5%
Primary heavy crude oil 16%| 15% 16%
Thermal heavy crude oil 12%| 11% 11%
Natural gas 44%| 45% 42%
================================================|==========================
48 CANADIAN NATURAL
Daily Production, Net of Royalties
2008| 2007 2006
------------------------------------------------|---------------------------
Crude oil and NGLs (bbl/d) |
North America 207,933| 210,769 205,382
North Sea 45,182| 55,825 59,940
Offshore West Africa 22,641| 26,012 35,212
------------------------------------------------|---------------------------
275,756| 292,606 300,534
------------------------------------------------|---------------------------
Natural gas (mmcf/d) |
North America 1,225| 1,378 1,185
North Sea 10| 13 15
Offshore West Africa 11| 11 9
------------------------------------------------|---------------------------
1,246| 1,402 1,209
------------------------------------------------|---------------------------
Total barrels of oil |
equivalent (boe/d) 483,541| 526,193 502,024
================================================|===========================
Daily production and per barrel statistics are presented throughout this
MD&A on a "before royalty" or "gross" basis. Production on an "after
royalty" or "net" basis is also presented.
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 averaged 564,845 boe/d for 2008, a 7% decrease from
609,206 boe/d for 2007 (2006 - 580,724 boe/d).
Total production of crude oil and NGLs before royalties decreased 5% to
315,667 bbl/d for 2008 from 331,232 bbl/d for 2007 (2006 - 331,998 bbl/d).
The decrease in crude oil and NGLs production from 2007 primarily
reflected lower production in the North Sea and Offshore West Africa due
to the timing of field turnarounds and the sale of the Company's working
interest in the B-Block Fields late in 2007, and in North America due to
the cyclic nature of the Company's thermal production. Crude oil and NGLs
production for 2008 was within the Company's previously issued guidance of
313,000 to 318,000 bbl/d.
Natural gas production continued to represent the Company's largest
product offering, accounting for 44% of the Company's total production in
2008. Total natural gas production before royalties decreased 10% to 1,495
mmcf/d for 2008 from 1,668 mmcf/d for 2007 (2006 - 1,492 mmcf/d). The
decrease in natural gas production from 2007 primarily reflected natural
production declines due to the Company's strategic decision to reduce
natural gas drilling activity to focus on higher return crude oil
projects. Natural gas production for 2008 was within the Company's
previously issued guidance of 1,492 to 1,506 mmcf/d.
For 2009, revised annual production is forecasted to average between
331,000 and 399,000 bbl/d of crude oil and NGLs and between 1,272 and
1,328 mmcf/d of natural gas.
North America
North America crude oil and NGLs production for 2008 decreased 1% to
average 243,826 bbl/d from 246,779 bbl/d for 2007 (2006 - 235,253 bbl/d).
The decrease in production from 2007 was primarily due to the cyclic
nature of the Company's thermal production.
North America natural gas production for 2008 decreased 10% to average
1,472 mmcf/d from 1,643 mmcf/d for 2007 (2006 - 1,468 mmcf/d). The
decrease in natural gas production from 2007 reflected production declines
due to the Company's strategic decision to reduce natural gas drilling
activity to focus on higher return crude oil projects.
North Sea
North Sea crude oil production for 2008 was 45,274 bbl/d, a decrease of
19% from 55,933 bbl/d for 2007 (2006 - 60,056 bbl/d) due to increased
planned maintenance, the sale of the Company's working interest in the
B-Block Fields late in 2007, expected production declines and delays in
development projects.
Offshore West Africa
Offshore West Africa crude oil production for 2008 decreased 7% to 26,567
bbl/d from 28,520 bbl/d for 2007 (2006 - 36,689 bbl/d). Production
decreased in 2008 due to expected production declines, partially offset by
a full year of production at the recently completed West Espoir development
and restoration of certain of the shut-in production at the Baobab Field
during the fourth quarter of 2008.
CANADIAN NATURAL 49
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 crude
oil volumes by segment, which have not been recognized in revenue, were as
follows:
(bbl) 2008| 2007 2006
----------------------------------------------------------------------------|---------------------------------
North America, related to pipeline fill 761,351| 1,097,526 1,097,526
North Sea, related to timing of liftings 558,904| 1,032,723 910,796
Offshore West Africa, related to timing of liftings 609,444| 8,578 113,774
----------------------------------------------------------------------------|---------------------------------
1,929,699| 2,138,827 2,122,096
============================================================================|=================================
During 2008, the North America pipeline fill was reduced, increasing cash
flow from operations by approximately $18 million.
In addition, during 2008, net production of approximately 127,000 barrels
of crude oil produced in the Company's international operations was
deferred and included in inventory at December 31, 2008. Notwithstanding
the overall increase in inventory, cash flow from operations increased by
approximately $5 million, as the increase in cash flow from additional
sales volumes in the North Sea more than offset the decrease in cash flow
from lower sales volumes in Offshore West Africa due to the timing of
liftings.
ROYALTIES
2008| 2007 2006
--------------------------------------------------|---------------------------
Crude oil and NGLs ($/bbl) (1)
North America $ 11.99 | $ 7.19 $ 5.86
North Sea $ 0.21 | $ 0.14 $ 0.13
Offshore West Africa $ 14.81 | $ 6.40 $ 2.81
Company average $ 10.48 | $ 5.94 $ 4.48
--------------------------------------------------|---------------------------
Natural gas ($/mcf) (1) |
North America $ 1.47 | $ 1.12 $ 1.31
Offshore West Africa $ 1.52 | $ 0.51 $ 0.22
Company average $ 1.46 | $ 1.11 $ 1.29
Company average ($/boe) (1) $ 9.78 | $ 6.26 $ 5.89
--------------------------------------------------|----------------------------
Percentage of revenue (2) |
Crude oil and NGLs 13% | 11% 8%
Natural gas 17% | 16% 19%
Boe 14% | 13% 12%
--------------------------------------------------|----------------------------
(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
Government royalties on a significant portion of North America crude oil
and NGLs production fall under the oil sands royalty regime and are
calculated on a project by project basis as a percentage of gross revenue
less operating, capital and abandonment costs ("net profit"). For 2008 and
prior years, royalties were calculated as 1% of gross revenues until the
Company's capital investments in the applicable project were fully
recovered, at which time the royalty increased to 25% of net profit.
Effective January 1, 2009, changes to the Alberta royalty regime under the
NRF include the implementation of a sliding scale for oil sands royalties
ranging from 1% to 9% on a gross revenue basis pre-payout and 25% to 40%
on a net revenue basis post-payout depending on benchmark crude oil
pricing.
In addition, effective January 1, 2009, new royalty formulas under the NRF
for conventional crude oil and natural gas are to operate on sliding
scales ranging up to 50%, determined by commodity prices and well
productivity.
Crude oil and NGLs royalties for 2008 continued to reflect strong realized
crude oil prices and averaged approximately 15% of gross revenues for 2008
and 2007 (2006 - 13%). North America crude oil and NGLs royalties per bbl
are anticipated to average 10% to 15% of gross revenue for 2009.
Natural gas royalties per mcf generally fluctuate with natural gas prices
and well productivity. Natural gas royalties averaged approximately 18% of
gross revenues for 2008 compared to 16% for 2007 (2006 - 19%), primarily
due to increased benchmark natural gas prices. North America natural gas
royalties per mcf are anticipated to average 14% to 18% of gross revenue
for 2009.
North Sea
North Sea government royalties on crude oil were eliminated effective
January 1, 2003. The remaining royalty is a gross overriding royalty on
the Ninian Field.
Offshore West Africa
Offshore West Africa production in both Cote d'Ivoire and Gabon is
governed by the terms of the various Production Sharing Contracts
("PSCs"). Under the PSCs, revenues are divided into cost recovery oil and
profit oil. Cost recovery oil allows the Company to recover its capital
and production costs and the costs carried by the Company on behalf of the
Government State Oil Companies. Profit oil is allocated to the joint
venture partners in accordance with their respective equity interests,
after a portion has been
50 CANADIAN NATURAL
allocated to the Governments. The Governments' share of profit oil
attributable to the Company's equity interest is allocated between royalty
expense and current income tax expense in accordance with the PSCs. The
Company's capital investments in the Espoir Fields in Cote d'Ivoire were
fully recovered in early 2007, increasing royalty rates and current income
taxes in accordance with the terms of the PSCs.
Royalty rates as a percentage of revenue averaged approximately 15% for
2008 compared to 9% for 2007 (2006 - 4%). The increase in royalty rates
from 2007 was due to the impact of the Company's full recovery of its
capital investment in the Espoir Fields in 2007 and the resulting increase
in profit oil on which the Government's entitlement is based. The increase
was compounded by the impact of the reduction in the Cote d'Ivoire
corporate income tax rate enacted early in 2008, which had the effect of
increasing the allocation of the Government's share of profit oil to
royalties. Offshore West Africa royalty rates are anticipated to average
6% to 10% of gross revenue for 2009, reflecting a lower price environment
and the Espoir Field contributing a lower proportion of the total Offshore
West Africa production.
PRODUCTION EXPENSE
2008| 2007 2006
-----------------------------------------------------|------------------------
Crude oil and NGLs ($/bbl) (1) |
North America $ 14.96| $ 12.26 $ 11.73
North Sea $ 26.29| $ 20.78 $ 17.57
Offshore West Africa $ 10.29| $ 8.32 $ 7.45
Company average $ 16.26| $ 13.34 $ 12.29
------------------------------------------------------|------------------------
Natural gas ($/mcf) (1) |
North America $ 1.00| $ 0.90 $ 0.81
North Sea $ 2.51| $ 2.17 $ 1.40
Offshore West Africa $ 1.61| $ 1.48 $ 1.19
Company average $ 1.02| $ 0.91 $ 0.82
------------------------------------------------------|------------------------
Company average ($/boe) (1) $ 11.79| $ 9.75 $ 9.14
======================================================|========================
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for 2008 increased 22%
to $14.96 per bbl from $12.26 per bbl for 2007 (2006 - $11.73 per bbl).
The increase in production expense per bbl from 2007 was primarily a
result of the higher cost of natural gas for fuel for the Company's
thermal operations and increased property tax and power costs. The
increase was also a result of the impact of lower production volumes on
the fixed cost portion of production costs.
North America natural gas production expense for 2008 increased 11% to
$1.00 per mcf from $0.90 per mcf for 2007 (2006 - $0.81 per mcf). The
increase in production expense per mcf from 2007 was primarily a result of
the Company's strategic reduction in natural gas drilling activity,
decreasing natural gas production throughout 2008 and increasing
production expense per mcf on the fixed cost portion of production costs.
Production expense per boe for 2009 is anticipated to increase as a result
of an overall reduction in budgeted volumes for 2009, while fixed costs,
such as property taxes and lease rentals, are forecasted to continue to
escalate.
North Sea
North Sea crude oil production expense increased on a per barrel basis
from 2007 primarily due to lower production volumes on a relatively fixed
operating cost base as well as due to higher planned maintenance costs.
Offshore West Africa
Offshore West Africa crude oil production expense increased on a per
barrel basis from 2007 primarily due to lower production volumes on a
relatively fixed operating cost base.
MIDSTREAM
($ millions) 2008| 2007 2006
---------------------------------------------------|---------------------------
Revenue $ 77| $ 74 $ 72
Production expense 25| 22 23
---------------------------------------------------|---------------------------
Midstream cash flow 52| 52 49
Depreciation 8| 8 8
---------------------------------------------------|---------------------------
Segment earnings before taxes $ 44| $ 44 $ 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.
CANADIAN NATURAL 51
DEPLETION, DEPRECIATION AND AMORTIZATION (1)
($ millions, except per boe amounts) (2) 2008| 2007 2006
--------------------------------------------------------|-----------------------
North America (3) $ 2,226| $ 2,350 $ 1,897
North Sea 317| 340 297
Offshore West Africa 132| 165 189
--------------------------------------------------------|-----------------------
Expense $ 2,675| $ 2,855 $ 2,383
$/boe $ 12.97| $ 12.84 $ 11.27
========================================================|======================
(1) DD&A excludes depreciation on midstream assets.
(2) Amounts expressed on a per unit basis are based on sales volumes.
(3) Amounts include the impact of intersegment eliminations. Depletion,
Depreciation and Amortization ("DD&A") expense for 2008 decreased 6%
to $2,675 million from $2,855 million for 2007 (2006 - $2,383
million), primarily due to the impact of lower sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) (1) 2008| 2007 2006
--------------------------------------------------------|-----------------------
North America $ 42| $ 38 $ 35
North Sea 27| 30 31
Offshore West Africa 2| 2 2
--------------------------------------------------------|-----------------------
Expense $ 71| $ 70 $ 68
$/boe $ 0.34| $ 0.32 $ 0.32
========================================================|=======================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in
the carrying amount of the asset retirement obligation due to the passage
of time. Accretion expense in 2008 was comparable to 2007.
ADMINISTRATION EXPENSE
($ millions, except per boe amounts) (1) 2008| 2007 2006
---------------------------------------------------------|----------------------
Expense $ 180| $ 208 $ 180
$/boe $ 0.87| $ 0.93 $ 0.85
=========================================================|======================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for 2008 decreased from 2007 primarily due to
decreased staffing costs, including costs related to the Company's share
bonus program, as well as due to decreased office lease costs.
STOCK-BASED COMPENSATION
($ millions) 2008 | 2007 2006
---------------------------------------------------------|----------------------
(Recovery) expense $ (52)| $ 193 $ 139
=========================================================|======================
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 as 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 $52 million ($38 million after-tax) stock-based
compensation recovery during 2008 due to a 33% decrease in the Company's
share price for the year ended December 31, 2008 (December 31, 2008 -
C$48.75; December 31, 2007 - C$72.58; December 31, 2006 - C$62.15; December
31, 2005 - C$57.63), offset by the impact of normal course graded vesting
of options granted in prior periods and the impact of vested options
exercised or surrendered during the year. As required by Canadian GAAP, the
Company records a liability for potential cash payments to settle its
outstanding employee stock options each reporting period 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 reporting date to reflect
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 net
earnings, or capitalized during the construction period in the case of the
Horizon Project. For the year ended December 31, 2008, the Company recorded
a $23 million recovery on previously capitalized stock-based compensation
on the Horizon Project (2007 - $58 million capitalized; 2006 - $79 million
capitalized).
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, 2008. In periods when
substantial stock price changes occur, the Company's 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.
52 CANADIAN NATURAL
For the year ended December 31, 2008, the Company paid $207 million for
stock options surrendered for cash settlement (2007 - $375 million; 2006 -
$264 million).
INTEREST EXPENSE
($ millions, except per boe amounts and 2008 | 2007 2006
interest rates) (1) |
---------------------------------------------------------|----------------------
Expense, gross $ 609 | $ 632 $ 336
Less: capitalized interest, Horizon Project 481 | 356 196
---------------------------------------------------------|----------------------
Expense, net $ 128 | $ 276 $ 140
$/boe $ 0.62 | $ 1.24 $ 0.66
---------------------------------------------------------|----------------------
Average effective interest rate 5.1%| 5.5% 5.7%
=========================================================|=====================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest expense and the Company's average effective interest rate
decreased from 2007 primarily due to a decrease in short term borrowing
rates during the last half of 2008 and the impact of the stronger Canadian
dollar during the first half of 2008.
On commencement of operations of Phase 1 of the Horizon Project, interest
capitalization will cease on this Phase and interest expense will increase
accordingly.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to manage its
commodity price, currency and interest rate exposures. The Company's risk
management program is not used for speculative purposes.
($ millions) 2008 | 2007 2006
---------------------------------------------------------|----------------------
Crude oil and NGLs financial instruments $ 2,020 | $ 505 $ 1,395
Natural gas financial instruments (21)| (343) (70)
Foreign currency contracts (139)| - -
---------------------------------------------------------|----------------------
Realized loss $ 1,860 | $ 162 $ 1,325
---------------------------------------------------------|----------------------
Crude oil and NGLs financial instruments $(3,104)| $ 1,244 $ (736)
Natural gas financial instruments 16 | 156 (260)
Foreign currency contracts (2)| - (17)
---------------------------------------------------------|----------------------
Unrealized (gain) loss $(3,090)| $ 1,400 $ (1,013)
---------------------------------------------------------|----------------------
Net (gain) loss $(1,230)| $ 1,562 $ 312
=========================================================|======================
The net realized loss (gain) from crude oil and natural gas financial
instruments would have decreased (increased) the Company's average realized
prices as follows:
2008 | 2007 2006
---------------------------------------------------------|----------------------
Crude oil and NGLs ($/bbl) (1) $ 17.45 | $ 4.18 $ 11.57
Natural gas ($/mcf) (1) $ (0.04)| $ (0.56) $ (0.13)
=========================================================|======================
(1) Amounts expressed on a per unit basis are based on sales volumes.
Complete details related to outstanding derivative financial instruments
at December 31, 2008 are disclosed in note 13 to the Company's consolidated
financial statements.
The commodity derivative financial instruments currently outstanding have
not been designated as hedges for accounting purposes (the "non-designated
hedges"). The fair value of these non-designated hedges is based on
prevailing forward commodity prices in effect at the end of each reporting
period and is reflected in risk management activities in consolidated net
earnings. The cash settlement amount of the commodity derivative financial
instruments may vary materially depending upon the underlying crude oil and
natural gas prices at the time of final settlement, as compared to their
mark-to-market value at December 31, 2008.
Due to changes in crude oil and natural gas forward pricing and the
reversal of prior period unrealized gains and losses, the Company recorded
a net unrealized gain of $3,090 million ($2,112 million after-tax) on its
risk management activities for the year ended December 31, 2008 (2007 -
$1,400 million unrealized loss, $977 million after-tax; 2006 - $1,013
million unrealized gain, $674 million after-tax).
FOREIGN EXCHANGE
($ millions) 2008| 2007 2006
--------------------------------------------------------|-----------------------
Net realized (gain) loss $ (114)| $ 53 $ (12)
Net unrealized loss (gain) (1) 832 | (524) 134
--------------------------------------------------------|-----------------------
Net loss (gain) $ 718 | $ (471) $ 122
========================================================|=======================
(1) Amounts are reported net of the effect of cross currency swap hedges.
CANADIAN NATURAL 53
The Company's North Sea operations are classified as self-sustaining for
the purposes of foreign currency translation. The North Sea operations are
initially measured in US dollars and then translated to Canadian dollars
using the current rate method, whereby assets and liabilities are
translated into Canadian dollars using the exchange rate in effect at the
balance sheet date, while revenue and expenses are translated into Canadian
dollars using the monthly average exchange rate. Foreign currency gains or
losses arising on the translation of non-US dollar monetary assets and
liabilities are included in net earnings while subsequent gains or losses
arising on translation to Canadian dollars are deferred and included in
accumulated other comprehensive income.
During 2008, the Company determined that its operations in Offshore West
Africa were now operationally and financially independent and the current
rate method of translation was prospectively adopted for translation of the
financial statements of the Offshore West African subsidiaries as at
December 31, 2008. Prior to this determination, the Company's Offshore West
Africa foreign operations were classified as integrated for the purposes of
foreign currency translation, and accordingly, Offshore West Africa foreign
operations and foreign currency transactions and balances held in North
America were directly translated into Canadian dollars using the temporal
method. All related foreign exchange gains or losses were included in net
earnings.
As a result of foreign currency translation, the Company's operating
results are affected by the fluctuations in 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 results in increased revenue from the sale of the Company's
production. Production expenses and future income tax liabilities in the
North Sea are subject to foreign currency fluctuations due to changes in
the exchange rate of the UK pound sterling to the US dollar. 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 net unrealized foreign exchange loss in 2008 was primarily related to
the weakening of the Canadian dollar in relation to the US dollar with
respect to the US dollar denominated debt, partially offset by the impact
of the re-measurement of North Sea future income tax liabilities
denominated in UK pounds sterling to US dollars. Included in the net
unrealized loss for the year ended December 31, 2008 was an unrealized gain
of $449 million related to the impact of cross currency swap hedges. The
net realized foreign exchange gain for 2008 was primarily due to the result
of foreign exchange rate fluctuations on settlement of working capital
items denominated in US dollars or UK pounds sterling and the repayment of
US dollar denominated debt. The Canadian dollar ended the year at US$0.8166
compared to US$1.0120 at December 31, 2007 (December 31, 2006 - US$0.8581).
TAXES
($ millions, except income tax rates) 2008 | 2007 2006
---------------------------------------------------------|----------------------
Current $ 245 | $ 121 $ 219
Deferred (67)| 44 37
---------------------------------------------------------|----------------------
Taxes other than income tax $ 178 | $ 165 $ 256
---------------------------------------------------------|----------------------
North America $ 33 | $ 96 $ 143
North Sea 340 | 210 30
Offshore West Africa 128 | 74 49
---------------------------------------------------------|----------------------
Current income tax 501 | 380 222
Future income tax 1,607 | (456) 652
---------------------------------------------------------|----------------------
2,108 | (76) 874
Income tax rate and other legislative change 41 | 864 395
(1) (2) (3) |
---------------------------------------------------------|----------------------
$ 2,149 | $ 788 $ 1,269
---------------------------------------------------------|----------------------
Effective income tax rate before income tax |
and other legislative changes 30.3%| 31.1% 37.3%
=========================================================|======================
(1) Includes the effects of one time recoveries of $19 million due to
British Columbia corporate income tax rate reductions and $22 million
due to Cote d'Ivoire corporate income tax rate reductions
substantively enacted or enacted during 2008.
(2) Includes the effect of one time recoveries of $864 million due to
Canadian Federal income tax rate reductions and other legislative
changes substantively enacted or enacted during 2007.
(3) Includes the effect of the following:
o a one time expense of $110 million related to the increased
supplementary charge on oil and gas profits in the UK North Sea
enacted in 2006.
o a one time recovery of $438 million due to Canadian Federal,
Alberta and Saskatchewan corporate income tax rate reductions
enacted in 2006.
o a one time recovery of $67 million due to Cote d'Ivoire, Offshore
West Africa corporate income tax rate reductions enacted in 2006.
Taxes other than income tax primarily includes current and deferred PRT,
which is charged on certain fields in the North Sea at the rate of 50% of
net operating income, after allowing for certain deductions including
related capital and 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 subsequent periods. North America current income taxes
have been provided on the basis of this corporate structure. In addition,
North America and North Sea current income taxes will vary depending on
available income tax deductions related to the nature, timing and amount of
capital expenditures incurred in any particular year.
For 2009, based on budgeted prices and the current availability of tax
pools, the Company expects to incur current income tax expense in Canada of
$20 million to $50 million and in the North Sea of $350 million to $450
million.
54 CANADIAN NATURAL
NET CAPITAL EXPENDITURES (1)
($ millions) 2008| 2007 2006
------------------------------------------------------|-----------------------
Expenditures on property, plant |
and equipment |
Net property acquisitions |
(dispositions) (2) $ 336| $ (39) $ 4,733
Land acquisition and retention 86| 95 210
Seismic evaluations 107| 124 130
Well drilling, completion and equipping 1,664| 1,642 2,340
Production and related facilities 1,282| 1,205 1,314
------------------------------------------------------|-----------------------
Total net reserve replacement expenditures 3,475| 3,027 8,727
------------------------------------------------------|-----------------------
Horizon Project: |
Phase 1 construction costs 2,732| 2,740 2,768
Phase 1 operating and capital inventory 87| - -
Phase 1 commissioning costs 277| - -
Phases 2/3 costs 336| 124 79
Capitalized interest, stock-based |
compensation and other 480| 437 338
--------------------------------------------------------|-----------------------
Total Horizon Project (3) 3,912| 3,301 3,185
--------------------------------------------------------|-----------------------
Midstream 9| 6 12
Abandonments (4) 38| 71 75
Head office 17| 20 26
--------------------------------------------------------|-----------------------
Total net capital expenditures $ 7,451| $ 6,425 $ 12,025
--------------------------------------------------------|-----------------------
By segment |
North America $ 2,344| $ 2,428 $ 7,936
North Sea 319| 439 646
Offshore West Africa 811| 159 134
Other 1| 1 11
Horizon Project 3,912| 3,301 3,185
Midstream 9| 6 12
Abandonments (4) 38| 71 75
Head office 17| 20 26
--------------------------------------------------------|-----------------------
Total $ 7,451| $ 6,425 $ 12,025
========================================================|=======================
(1) Net capital expenditures exclude adjustments related to differences
between carrying value and tax value, and other fair value
adjustments.
(2) Includes Business Combinations.
(3) Net expenditures for the Horizon Project also include the impact of
intersegment eliminations.
(4) Abandonments represent expenditures to settle ARO and have been
reflected as capital expenditures in this table.
The Company's operating 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 for 2008 were $7,451 million compared to $6,425
million for 2007 (2006 - $12,025 million). Excluding the ACC acquisition,
net capital expenditures were $7,270 million for 2006. Capital expenditures
in 2008 primarily reflected the continued progress on the Company's larger,
future growth projects, most notably the Horizon Project, Primrose East,
and Gabon, offset by the effects of an overall strategic reduction in the
North America natural gas drilling program.
During 2008, the Company drilled a total of 1,121 net wells consisting of
269 natural gas wells, 682 crude oil wells, 131 stratigraphic test and
service wells, and 39 wells that were dry. This compared to 1,322 net wells
drilled for 2007 (2006 - 1,738 net wells). The Company achieved an overall
success rate of 96% for 2008, excluding the stratigraphic test and service
wells (2007 - 91%; 2006 - 91%).
North America
North America, excluding the Horizon Project, accounted for approximately
32% of the total capital expenditures for the year ended December 31, 2008
compared to approximately 39% for 2007 (2006 - 67%).
During 2008, the Company targeted 280 net natural gas wells, including 27
wells in Northeast British Columbia, 104 wells in the Northern Plains
region, 70 wells in Northwest Alberta, and 79 wells in the Southern Plains
region. The Company also targeted 704 net crude oil wells during the year.
The majority of these wells were concentrated in the Company's crude oil
Northern Plains region where 415 primary heavy crude oil wells, 110 Pelican
Lake crude oil wells, 74 thermal crude oil wells and 7 light crude oil
wells were drilled. Another 98 wells targeting light crude oil were drilled
outside the Northern Plains region.
Due to significant differences in relative commodity prices between crude
oil and natural gas throughout most of 2008, the Company continued to
access its large crude oil drilling inventory to maximize value in both the
short and long term. Due to the
CANADIAN NATURAL 55
Company's focus on drilling crude oil wells in 2007 and 2008 and as a
result of royalty changes under the Alberta NRF, natural gas drilling
activities have been reduced to manage overall capital spending. Deferred
natural gas well locations have been retained in the Company's prospect
inventory.
As part of the phased expansion of its In-Situ Oil Sands Assets, the
Company is continuing to develop its Primrose thermal projects. During
2008, the Company drilled 74 thermal oil wells, 2 water source wells, and
19 stratigraphic test wells and observation wells. Overall Primrose thermal
production for 2008 was approximately 65,000 bbl/d (2007 - 64,000 bbl/d;
2006 - 64,000 bbl/d).
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, was completed and first steaming commenced in
September 2008, with first production achieved in the fourth quarter of
2008. Subsequent to December 31, 2008, operational issues on one of the
pads has caused steaming to cease on all well pads in the Primrose East
project area and the Company is working on rectifying the issues.
The next planned phase of the Company's In-Situ Oil Sands assets expansion
is the Kirby project located 120 kilometers north of the existing Primrose
facilities. During 2007, the Company filed a combined application and
Environmental Impact Assessment for this project with Alberta Environment
and the Alberta Energy and Utilities Board. Final corporate sanction and
project scope will be impacted by environmental regulations and their
associated costs. Subject to regulatory approval, crude oil pricing, and
capital costs, the Company may proceed with the detailed engineering and
design work.
Development of new pads and secondary recovery conversion projects at
Pelican Lake continued as expected throughout 2008. Drilling consisted of
110 horizontal crude oil wells, with plans to drill 58 additional
horizontal crude oil wells in 2009. The response from the water and polymer
flood projects continues to be positive. Pelican Lake production averaged
approximately 37,000 bbl/d in 2008 (2007 - 34,000 bbl/d; 2006 - 30,000
bbl/d).
For 2009, the Company's overall drilling activity in North America is
expected to comprise approximately 142 natural gas wells and 465 crude oil
wells, excluding stratigraphic and service wells.
Horizon Project
The Company continued the construction, commissioning and staged start up
of the Horizon Project, with first production of synthetic crude oil from
Phase 1 achieved February 28, 2009, representing a major milestone.
Currently, the Company is filling all product tanks in preparation for
blending and pipeline shipment.
All major components have been completed and are fully operational, with
the exception of the Distillate Hydrotreating Plant (Plant 42). The Naphtha
and Gas Oil Hydrotreaters (Plants 41 and 43 respectively) are fully
operational and currently capable of producing approximately 55,000 bbl/d.
Upon completion of Plant 42, the focus will be on reaching full production
capacity of 110,000 bbl/d. Plant 42 has now been turned over to operations
for commissioning and is targeted to be operational by the end of April
2009, subject to any unforeseen start up issues.
During the initial stages of the ramp-up of production, the production
volumes will fluctuate on a weekly basis until the end of the second
quarter of 2009 when the Company expects to see a steady ramp up to full
production by the end of 2009. The Company will work towards full capacity
throughout 2009 as the plant continues to be fine tuned to design rates
with a focus on safety and reliability.
Phase 1 of the Horizon Project was designed, engineered, and constructed in
an extremely volatile and inflationary business environment with final
construction costs totaling approximately $9.7 billion. Subsequent planned
expansion through Phases 2/3, further broken down into a series of four
Tranches, are being reprofiled with the goal of attaining better cost
management.
North Sea
In 2008, the Company continued with its planned program of infill drilling,
recompletions, workovers and waterflood optimizations. During 2008, 4.1 net
wells were drilled, including 0.9 net water injectors, with an additional
1.2 net wells drilling at year end. Specifically, two production wells were
completed at Murchison and one production well was completed at Ninian,
with an additional production well in progress at Ninian at year end. The
Company also delivered one water injection well at Ninian and further
increased volumes injected into the Ninian reservoir.
The Company continued with its planned investment in its long-term
facilities and infrastructure strategy and successfully carried out
maintenance turnarounds at all five installations during the year. Within
the Murchison turnaround the Company successfully implemented a new control
system, which has resulted in improved platform uptime.
Offshore West Africa
During 2008, 4.1 net wells were drilled with 0.9 net wells drilling at year
end.
Development drilling on West Espoir was completed in early 2008, on budget
and on time. At the Baobab Field, the Company delivered three new wells
from the drilling program, with a fourth well due to be completed in the
second quarter of 2009.
At the 90% owned and operated Olowi Field in offshore Gabon, the Conductor
Supported Platform was installed, construction was completed on the FPSO,
which arrived on location in February 2009, and construction continued on
the wellhead towers and subsea facilities. First crude oil is targeted for
late in the first quarter or early in the second quarter of 2009.
56 CANADIAN NATURAL
LIQUIDITY AND CAPITAL RESOURCES
($ millions, except ratios) 2008 | 2007 2006
--------------------------------------------------------|----------------------
Working capital (deficit) (1) $ 392 | $ (1,382) $ (832)
Long-term debt (2)(3) $ 13,016 | $ 10,940 $ 11,043
Shareholders' equity |
Share capital $ 2,768 | $ 2,674 $ 2,562
Retained earnings 15,344 | 10,575 8,141
Accumulated other comprehensive income |
(loss) 262 | 72 (13)
--------------------------------------------------------|----------------------
Total $ 18,374 | $ 13,321 $ 10,690
--------------------------------------------------------|----------------------
Debt to book capitalization (3)(4) 41%| 45% 51%
Debt to market capitalization (3)(5) 33%| 22% 25%
After tax return on average common |
shareholders' equity (6) 33%| 22% 27%
After tax return on average capital |
employed (3)(7) 19%| 12% 17%
========================================================|======================
(1) Calculated as current assets less current liabilities, excluding the
current portion of long-term debt.
(2) Includes the current portion of long-term debt (2008 - $420 million;
2007 and 2006 - $nil).
(3) Long-term debt at December 31, 2008 and 2007 is stated at its carrying
value, net of fair value adjustments, original issue discounts and
transaction costs. Amounts for 2006 were not adjusted for these items.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value
of common shareholders' equity plus current and long-term debt.
(6) Calculated as net earnings for the year; as a percentage of average
common shareholders' equity for the year.
(7) 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, including $10,678 million in average capital
employed related to the Horizon Project (2007 - $7,001 million; 2006 -
$3,760 million).
At December 31, 2008, the Company's capital resources consisted primarily
of cash flow from operations, available bank 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 bank 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.
The ongoing worldwide financial and economic events have resulted in a
significant tightening of the availability and cost of new sources of
liquidity including bank credit facilities and funds derived from debt
capital markets. In light of these credit challenges, the Company has
undertaken a thorough review of its liquidity sources as well as its
exposure to counterparties and has concluded that its capital resources are
sufficient to meet ongoing short-, medium- and long-term commitments.
Specifically, the Company continues to believe that its internally
generated cash flow from operations supported by the implementation of its
hedge policy, the flexibility of its capital expenditure programs supported
by its multi-year financial plans, its existing bank credit facilities and
its ability to raise new debt on commercially acceptable terms, will
provide sufficient liquidity to sustain its operations in the short, medium
and long term and support its growth strategy. Further, the Company
believes that its counterparties currently have the financial capacity to
settle outstanding obligations in the normal course of business.
On an ongoing basis, the Company continues to focus on the following areas:
o Monitoring cash flow from operations, which is the primary source of
funds;
o Reviewing bank credit facilities and public debt indentures to ensure
they are in compliance with applicable covenant packages;
o Monitoring credit markets, governments, world banks and the Company's
bank syndicates to identify associated risks and exposures;
o Maintaining an active commodity risk management program that manages
exposure to crude oil and natural gas price volatility. The Company
believes this is an effective tool to manage short- and medium-term
changes in spot commodity prices. The Company also monitors its
commodity risk management counterparties to ensure they are in
position to settle obligations within the contractually agreed terms
of settlement;
o Monitoring exposure to individual customers, contractors, suppliers
and joint venture partners on a regular basis and when appropriate,
ensuring parental guarantees or letters of credit are in place to
minimize the impact in the event of default; and
o Monitoring the Company's 2009 capital and operating plans to provide
the required flexibility to deal with commodity price volatility,
commitments in respect of capital and operating expenditures, and
commitments to retire its non-revolving bank credit facility maturing
in October 2009. The Company actively manages the allocation of
maintenance and growth capital to ensure it is expended in a prudent
and appropriate manner. The Company continued the construction,
commissioning and staged start up of the Horizon Project, with first
production of synthetic crude oil from Phase 1 achieved February 28,
2009.
At December 31, 2008, the Company had $2,082 million of available credit
under its bank credit facilities, which together with cash flow from
operating activities to be generated in 2009 supported by its commodity
risk management program and the ability to actively manage the capital
expenditure programs, is forecasted to be sufficient to repay the $2,350
million non-revolving bank credit facility maturing October 2009. Further,
the Company's current debt ratings are BBB (high) with a negative trend by
DBRS Limited, Baa2 with a stable outlook by Moody's Investors Service and
BBB with a stable outlook by Standard & Poor's.
CANADIAN NATURAL 57
Further details related to the Company's long-term debt at December 31,
2008 are discussed below and in note 5 to the Company's audited annual
consolidated financial statements.
At December 31, 2008, the Company's working capital was $392 million,
excluding the current portion of long-term debt and including both the
current portion of the net mark-to-market asset for risk management
derivative financial instruments of $1,851 million and the current portion
of the stock-based compensation liability of $159 million, together with
related future income tax liabilities of $585 million. The cash settlement
amount of the risk management derivative financial instruments may vary
materially depending upon the underlying crude oil and natural gas prices
at the time of final settlement, as compared to their mark-to-market value
at December 31, 2008. 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.
Long-term debt was $13,016 million at December 31, 2008, resulting in a
debt to book capitalization level of 41% as at December 31, 2008 (December
31, 2007 - 45%; December 31, 2006 - 51%). This ratio is near the midpoint
of the 35% to 45% range targeted by management, including the impact of
capital spending on the Horizon Project. The Company remains committed to
maintaining a strong balance sheet and flexible capital structure. The
Company has hedged a portion of its crude oil and natural gas production
for 2009 and 2010 at prices that protect investment returns to ensure
ongoing balance sheet strength and the completion of its capital
expenditure programs. In the future, the Company may also consider the
divestiture of certain 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 prices and supports the Company's cash flow for its capital
expenditures programs. This program currently allows for the hedging of up
to 60% of the near 12 months budgeted production and up to 40% of the
following 13 to 24 months estimated production. For the purpose of this
program, the purchase of crude oil put options is in addition to the above
parameters. As at December 31, 2008, in accordance with the policy,
approximately 6% of budgeted crude oil volumes were hedged using collars
for 2009 and approximately 33% of budgeted natural gas volumes were hedged
for the first quarter of 2009. In addition, 92,000 bbl/d of crude oil
volumes are protected by put options for 2009 at a strike price of
US$100.00 per bbl.
The Company had the following net commodity derivative financial
instruments outstanding as at December 31, 2008:
Remaining term Volume Weighted average price Index
----------------------------------------------------------------------------------------------------------
Crude oil
Crude oil price collars Jan 2009 - Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Apr 2009 - Jun 2009 4,000 bbl/d US$70.00 - US$90.00 WTI
Crude oil puts Jan 2009 - Dec 2009 92,000 bbl/d US$100.00 WTI
---------------------------------------------------------------------
Natural gas
Natural gas price collars(1) Jan 2009 - Mar 2009 500,000 GJ/d C$6.00 - C$8.63 AECO
----------------------------------------------------------------------------------------------------------
(1) Subsequent to December 31, 2008, the Company entered into 220,000 GJ/d
of C$6.00 - C$8.00 natural gas AECO collars for the period January to
December 2010.
The Company's outstanding commodity derivative financial instruments are
expected to be settled monthly based on the applicable index pricing for
the respective contract month.
In addition to the financial derivatives noted above, subsequent to
December 31, 2008, the Company entered into natural gas physical sales
contracts for 400,000 GJ/d at an average fixed price of C$5.29 per GJ at
AECO for the period April to December 2009.
LONG-TERM DEBT
The Company's long-term debt of $13,016 million at December 31, 2008 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, 2008, the Company had in place unsecured bank credit
facilities of $6,232 million, comprised of:
o a $125 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009, as discussed below;
o a revolving syndicated credit facility of $2,230 million maturing June
2012;
o a revolving syndicated credit facility of $1,500 million maturing June
2012; and
o a (pound)15 million demand credit facility related to the Company's
North Sea operations.
During 2007, one of the revolving syndicated credit facilities was
increased from $1,825 million to $2,230 million and a $500 million demand
credit facility was terminated. The revolving syndicated credit facilities
were also extended and now mature June 2012. 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. Borrowings
under these facilities can be made by way of Canadian dollar and US dollar
bankers' acceptances, and LIBOR, US base rate and Canadian prime loans.
58 CANADIAN NATURAL
In conjunction with the closing of the acquisition of ACC in November 2006,
the Company executed a $3,850 million, non-revolving syndicated credit
facility maturing October 2009. In March 2007, $1,500 million was repaid,
reducing the facility to $2,350 million. During 2009, the Company plans to
fully retire this facility from its existing borrowing capacity under its
other long-term bank credit facilities, which were $2,050 million at
December 31, 2008, supported by cash flow from operating activities,
including the commodity risk management activities. In accordance with
these plans, and repayments of $420 million made subsequent to December 31,
2008 on this facility, $420 million has been classified as current.
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $372 million, including $300 million related to the
Horizon Project, were outstanding at December 31, 2008.
Medium-term notes
The Company has $2,600 million remaining on its outstanding $3,000 million
base shelf prospectus filed in September 2007 that allows for the issue of
medium-term notes in Canada until October 2009. If issued, these securities
will bear interest as determined at the date of issuance.
In December 2007, the Company issued $400 million of unsecured notes
maturing December 2010, bearing interest at 5.50%. Proceeds from the
securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities.
During 2007, $125 million of 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%, with the
final annual principal repayment of US$31 million due in May 2009. During
2008 and 2007, US$31 million of the senior unsecured notes were repaid each
year.
US Dollar Debt Securities
In January 2008, the Company issued US$1,200 million of unsecured notes
under a US base shelf prospectus, comprised of US$400 million of 5.15%
unsecured notes due February 2013, US$400 million of 5.90% unsecured notes
due February 2018, and US$400 million of 6.75% unsecured notes due February
2039. 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 US$1,800 million remaining on its outstanding
US$3,000 million base shelf prospectus filed in September 2007 that allows
for the issue of US dollar debt securities in the United States until
October 2009. If issued, these securities will bear interest as determined
at the date of issuance.
During 2008, US$8 million of US dollar debt securities were repaid.
In March 2007, the Company issued US$2,200 million of unsecured notes,
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 swaps to fix the Canadian dollar interest and principal
repayment amounts on the entire 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 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. Proceeds from the securities issued were used to repay
bankers' acceptances under the Company's bank credit facilities.
During 2008, the Company terminated the interest rate swaps that had been
designated as a fair value hedge of US$350 million of 5.45% unsecured notes
due October 2012. Accordingly, the Company ceased revaluing the related
debt from the date of termination of the interest rate swaps for subsequent
changes in fair value. The fair value adjustment of $20 million at the date
of termination is being amortized to interest expense over the remaining
term of the debt.
During 2007, the Company de-designated the portion of the US dollar
denominated debt previously hedged against its net investment in US dollar
based self-sustaining foreign operations. Accordingly, all foreign exchange
(gains) losses arising each period on US dollar denominated long-term debt
are now recognized in the consolidated statements of earnings.
SHARE CAPITAL
As at December 31, 2008, there were 540,991,000 common shares outstanding
and 30,962,000 stock options outstanding. As at March 3, 2009, the Company
had 541,149,000 common shares outstanding and 30,285,000 stock options
outstanding.
The Company did not renew the Normal Course Issuer Bid during 2008. During
2007 and 2008, the Company did not purchase any common shares for
cancellation (2006 - 485,000 common shares were purchased at an average
price of $57.33 per common share for a total cost of $28 million).
In March 2009, the Company's Board of Directors approved an increase in the
annual dividend paid by the Company to $0.42 per common share for 2009. The
increase represents a 5% increase from the prior year. The dividend policy
undergoes a periodic review by the Board of Directors and is subject to
change. In February 2008, an increase in the annual dividend paid by the
Company was approved to $0.40 per common share for 2008. The increase
represented an 18% increase from 2007.
CANADIAN NATURAL 59
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations.
These commitments primarily relate to firm commitments for gathering,
processing and transmission services; operating leases relating to offshore
FPSOs, drilling rigs and office space; expenditures relating to ARO; as
well as long-term debt and interest payments. As at December 31, 2008, no
entities were consolidated under CICA Handbook accounting Guideline 15,
"consolidation of Variable Interest Entities". The following table
summarizes the Company's commitments as at December 31, 2008:
($ millions) 2009 2010 2011 2012 2013 Thereafter
----------------------------------------------------------------------------------------------------------------
Product transportation and $ 219 $ 184 $ 159 $ 133 $ 124 $ 1,175
pipeline
Offshore equipment operating $ 175 $ 145 $ 144 $ 116 $ 117 $ 398
lease
Offshore drilling $ 251 $ 62 $ - $ - $ - $ -
Asset retirement obligations (1) $ 6 $ 7 $ 6 $ 6 $ 6 $ 4,443
Long-term debt (2) $ 2,385 $ 400 $ 490 $ 429 $ 890 $ 6,707
Interest expense(3) $ 610 $ 565 $ 543 $ 490 $ 428 $ 5,992
Office lease $ 25 $ 29 $ 23 $ 2 $ 2 $ 1
Other $ 321 $ 180 $ 17 $ 12 $ 8 $ 19
================================================================================================================
(1) Amounts represent management's estimate of the future undiscounted
payments to settle ARO related to resource properties, facilities, and
production platforms, based on current legislation and industry
operating practices. Amounts disclosed for the period 2009 - 2013
represent the minimum required expenditures to meet these obligations.
Actual expenditures in any particular year may exceed these minimum
amounts.
(2) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or
transaction costs. No debt repayments are reflected for $1,725 million
of revolving bank credit facilities due to the extendable nature of
the facilities.
(3) Interest expense amounts represent the scheduled fixed rate and
variable rate cash payments related to long-term debt. Interest on
variable rate long-term debt was estimated based upon prevailing
interest rates as of December 31, 2008.
LEGAL PROCEEDINGS
The Company is defendant and plaintiff in a number of legal actions that
arise in the normal course of business. In addition, the Company is subject
to certain contractor construction claims related to the Horizon Project.
The Company believes that any liabilities that might arise pertaining to
any such matters would not have a material effect on its consolidated
financial position.
RESERVES
For the year ended December 31, 2008, the Company retained a qualified
independent reserves evaluator, Sproule Associates Limited ("Sproule"), to
evaluate 100% of the Company's conventional proved, as well as proved and
probable crude oil, NGLs and natural gas reserves(1) and prepare Evaluation
Reports on these reserves. The Company has been granted an exemption from
certain of the provisions of 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 three principal differences between the two
standards. The first is 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. 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 third is
the requirement to disclose a gross reserve reconciliation (before the
consideration of royalties). The Company discloses its conventional crude
oil, NGLs and natural gas reserve reconciliations net of royalties in
adherence to SEC requirements.
The Company annually discloses 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 the Company's annual report and in its
annual Form 40-F filing with the SEC. 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 additional voluntary
information, which is disclosed in the Company's Annual Information Form.
(1) Conventional crude oil, NGLs and natural gas reserves include all of
the Company's light/medium, primary heavy, and thermal crude oil,
natural gas, coal bed methane and NGLs reserves. They do not include
the Company's oil sands mining reserves.
(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. Future development costs and associated
material well abandonment liabilities have been applied.
60 CANADIAN NATURAL
The following tables summarize the Company's proved conventional crude oil
and natural gas reserves, net of royalties, as at December 31, 2008 and
2007:
North Offshore
Crude oil and NGLs (mmbbl) America North Sea West Africa Total
---------------------------------------------------------------------------------------------
Net conventional proved reserves
Reserves, December 31, 2007 920 310 128 1,358
Extensions and discoveries 51 - - 51
Improved recovery 17 6 4 27
Purchases of reserves in place - - - -
Sales of reserves in place - - - -
Production (76) (17) (8) (101)
Economic revisions due to prices 28 (81) 8 (45)
Revisions of prior estimates 8 38 10 56
---------------------------------------------------------------------------------------------
Reserves, December 31, 2008 948 256 142 1,346
==============================================================================================
The Company's net proved conventional crude oil reserves at December 31,
2008 totaled 1,346 mmbbl. Approximately 88% of production was replaced by
reserve additions during 2008. Extensions and discoveries resulting from
exploration and development activities amounted to 51 mmbbl, while net
positive revisions amounted to 11 mmbbl.
Natural gas (bcf) North Offshore Total
America North Sea West Africa
--------------------------------------------------------------------------------------------
Net conventional proved reserves
Reserves, December 31, 2007 3,521 81 64 3,666
Extensions and discoveries 140 - - 140
Improved recovery 52 (1) 6 57
Purchases of reserves in place 77 - - 77
Sales of reserves in place (1) - - (1)
Production (449) (4) (4) (457)
Economic revisions due to prices (19) (56) 6 (69)
Revisions of prior estimates 202 47 22 271
---------------------------------------------------------------------------------------------
Reserves, December 31, 2008 3,523 67 94 3,684
=============================================================================================
The Company's net proved conventional natural gas reserves at December 31,
2008 totaled 3,684 bcf. Approximately 104% of production was replaced by
reserve additions during 2008. Extensions and discoveries resulting from
exploration and development activities amounted to 140 bcf, while net
positive revisions amounted to 202 bcf.
For the year ended December 31, 2008, the Company retained a qualified
independent reserves evaluator, GLJ Petroleum Consultants Ltd. ("GLJ"), to
evaluate Phase 1 to Phase 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. 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
proved and probable crude oil, NGLs and natural gas reserves.
Synthetic crude oil reserves (1)
Net reserves, after royalties (mmbbl) 2008| 2007
-----------------------------------------------------------------|--------------
Proved 1,946| 1,761
Proved and probable 2,944| 2,680
=================================================================|==============
(1) SCO reserves are based on the upgrading of bitumen using technologies
implemented at the Horizon Project.
The net proved SCO reserves increased by 185 mmbbl, while net proved and
probable SCO reserves increased by 264 mmbbl. The increases are primarily
due to a low constant dollar crude oil price, deferring project payout and
thereby reducing royalties paid.
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
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.
CANADIAN NATURAL 61
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 into SCO. These inherent risks include, but
are not limited to, the following items:
o Economic risk of finding, producing and replacing 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, ARO and depletion rates;
o Prevailing prices of crude oil and natural gas;
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 on commercially acceptable terms;
o Foreign exchange risk due to fluctuating exchange rates on the
Company's US dollar denominated debt and as the majority of sales are
based in US dollars;
o Environmental impact risk associated with exploration and development
activities, including GHG;
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 operations; and
o Other circumstances affecting revenue and expenses.
The Company uses a variety of means to help mitigate and/or minimize these
risks. The Company maintains a comprehensive property loss and business
interruption insurance program to reduce risk to an acceptable level.
Operational control is enhanced by focusing efforts on large core areas
with high working interests and by assuming operatorship of key facilities.
Product mix is diversified, consisting of the production of natural gas and
the production of crude oil of various grades. The Company believes this
diversification reduces price risk when compared with over-leverage to one
commodity. Accounts receivable from the sale of crude oil and natural gas
are mainly with customers in the crude oil and natural gas industry and are
subject to normal industry credit risks. The Company manages these risks by
reviewing 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. Substantially all of
the Company's accounts receivables are due within normal trade terms.
Derivative financial instruments are utilized to help ensure targets are
met and to manage commodity prices, foreign currency rates and interest
rate exposure. The Company is exposed to possible losses in the event of
nonperformance by counterparties to derivative financial instruments;
however, the Company manages this credit risk by entering into agreements
with substantially all investment grade financial institutions and other
entities. The arrangements and policies concerning the Company's financial
instruments are under constant review and may change depending upon the
prevailing market conditions.
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 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. 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"). Details of the plan
and the results are presented to, and reviewed by, the Board of Directors
quarterly.
The Company's plan and operating guidelines focus on minimizing the impact
of operations while meeting regulatory requirements, regional management
frameworks, industry operating standards and guidelines, and internal
corporate standards. The Company, as part of this Plan, has implemented a
proactive program that includes:
o An 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;
62 CANADIAN NATURAL
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;
o A program to replace the majority of fresh water for steaming with
brackish water;
o Environmental planning for all projects to assess impacts and to
implement avoidance and mitigation programs;
o Reporting for environmental liabilities;
o A program to optimize efficiencies at the Company's operating
facilities; and
o Continued evaluation of new technologies to reduce environmental
impacts.
The Company has also established stringent operating standards in four
areas:
o Implementing cost effective ways of reducing GHG emissions per unit of
production;
o Exercising care with respect to all waste produced through effective
waste management plans;
o Using water-based, environmentally friendly drilling muds whenever
possible; and
o Minimizing produced water volumes onshore and offshore through
cost-effective measures.
For 2008, the Company's capital expenditures included $38 million for
abandonment expenditures (2007 - $71 million; 2006 - $75 million).
The Company's estimated undiscounted ARO at December 31, 2008 was as
follows:
Estimated ARO, undiscounted ($ millions) 2008 | 2007
-----------------------------------------------------------------|--------------
North America, including Horizon Project $ 3,165 | $ 3,038
North Sea 1,216 | 1,286
Offshore West Africa 93 | 102
-----------------------------------------------------------------|--------------
4,474 | 4,426
North Sea PRT recovery (529)| (555)
-----------------------------------------------------------------|--------------
$ 3,945 | $ 3,871
=================================================================|==============
The estimate of ARO is based on estimates of future costs to abandon and
restore 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 estimated to result in a PRT recovery of $529 million
(2007 - $555 million; 2006 - $625 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
undiscounted abandonment liability to $3,945 million (2007 - $3,871
million).
GREENHOUSE GAS AND OTHER AIR EMISSIONS
The Company, through the Canadian Association of Petroleum Producers
("CAPP"), is working with legislators and regulators as they develop and
implement new GHG emission laws and regulations. Internally, the Company is
pursuing an integrated emissions reduction strategy to ensure that it is
able to comply with existing and future emissions reduction requirements.
The Company continues to develop strategies that will enable it to deal
with the risks and opportunities associated with new GHG and air emissions
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.
In Canada, the Federal Government has indicated its intent to develop
regulations that would be in effect in 2010 to address industrial GHG
emissions. The Federal Government has also outlined national and sectoral
reduction targets for several categories of air pollutants. In Alberta, GHG
regulations came into effect July 1, 2007, affecting facilities emitting
more than 100 kilotonnes of CO2e annually. Two of the Company's facilities,
the Primrose/Wolf Lake in-situ heavy crude oil facilities and the Hays sour
natural gas plant, fall under the regulations. Commencing July 1, 2008, the
British Columbia carbon tax is being assessed at $10/tonne of CO2e on fuel
consumed in the province, increasing to $30/tonne by July 1, 2012. In the
UK, GHG regulations have been in effect since 2005. During phase 1 (2005 -
2007) of the UK National Allocation Plan, the Company operated below its
CO2 allocation. For phase 2 (2008 - 2012) the Company's CO2 allocation has
been decreased below the Company's estimated current operations emissions.
The Company continues to focus on implementing reduction programs based on
efficiency audits to reduce CO2 emissions at its major facilities and on
trading mechanisms to ensure compliance with requirements now in effect.
There are a number of unresolved issues in relation to Canadian Federal and
Provincial GHG regulatory requirements. Key among them is an appropriate
facility emission threshold, availability and duration of compliance
mechanisms, and resolution of federal/provincial harmonization agreements.
The Company continues to pursue GHG emission reduction initiatives
including solution
CANADIAN NATURAL 63
gas conservation, CO2 capture and sequestration in oil sands tailings, CO2
capture and storage in association with enhanced oil recovery, and
participation in an industry initiative to promote an integrated CO2
capture and storage network.
The additional requirements of enacted or proposed GHG legislation on the
Company's operations will 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.
Air pollutant standards and guidelines are being developed federally and
provincially and the Company is participating in these discussions. Ambient
air quality and sector based reductions in air emissions are being
reviewed. Through Company and industry participation with stakeholders,
guidelines have been developed that adopt a structured process to emission
reductions that is commensurate with technological development and
operational requirements.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to make
judgements, assumptions and estimates in the application of Canadian GAAP
that have a significant impact on the financial results of the Company.
Actual results may differ from those estimates, and those differences may
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 a
gain or loss except where such dispositions result in a change in the
depletion rate of the specific cost centre of 20% or more. Under Canadian
GAAP, substantially all of the capitalized costs and estimated 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 single-day, year-end prices and costs ("constant dollar pricing") as
required by the SEC for US GAAP purposes.
Under Canadian GAAP, 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. No ceiling test impairments were
recognized under Canadian GAAP at December 31, 2008, as future net revenues
exceeded capitalized costs. Under US GAAP, the ceiling test differs from
Canadian GAAP in that future net revenues from proved reserves are based on
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 in the current year resulted in the
recognition of an after-tax ceiling test impairment of $6,164 million for
US GAAP purposes.
The US GAAP ceiling test is based on constant dollar pricing and is highly
sensitive to differences in benchmark pricing and the Heavy Differential in
effect at year end as opposed to pricing throughout the year. As the
Company's crude oil production is weighted towards heavier grades of crude
oil, which have historically traded at lower prices at year end due to
normal seasonality, constant dollar pricing in effect at year end is
generally not representative of average pricing realized throughout the
year. Had the US GAAP ceiling test at December 31, 2008 been prepared using
average realized pricing throughout 2008, rather than constant dollar
pricing, and assuming no other changes in reserves, operating costs, or
future development costs, the Company would not have recognized a ceiling
test impairment loss in the current year for US GAAP purposes.
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 estimation of reserves involves the exercise of judgement. Forecasts
are based on engineering data, estimated future prices, expected future
rates of production and the timing and amount 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 either 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 may also result in
an impairment of crude oil and natural gas property, plant and equipment
carrying amounts under the ceiling test.
64 CANADIAN NATURAL
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.
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 are capitalized as part of the
cost of associated capital assets and are amortized to expense through
depletion over the life of the asset. The fair value of the 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 retirement 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 may 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 and the Horizon Project upgrader and related
infrastructure) 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 between the
carrying value of assets and liabilities in the consolidated financial
statements and their respective tax bases, using income tax rates
substantively enacted or enacted as of the consolidated balance sheet date.
Accounting for income taxes is a complex process that requires management
to interpret frequently changing laws and regulations (e.g. Changing income
tax rates) and make certain judgements with respect to the application of
tax law, estimating the timing of temporary difference reversals, and
estimating the realizability of tax assets. 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 derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. These
financial instruments are entered into solely for hedging purposes and are
not used for speculative purposes.
The estimated fair value of derivative financial instruments has been
determined based on appropriate internal valuation methodologies and/or
third party indications. Fair values determined using valuation models
require the use of assumptions concerning the amount and timing of future
cash flows and discount rates. In determining these assumptions, the
Company has relied primarily on external readily observable market inputs
including quoted commodity prices and volatility, interest rate yield
curves, and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that may be realized or
settled in a current market transaction and these differences may be
material.
Purchase Price Allocations
The purchase prices 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
judgements 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 internal engineers and outside
consultants. The judgements 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.
CANADIAN NATURAL 65
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, 2008, 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
the Company's management to allow timely decisions regarding required
disclosures.
The Company's management, including 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, 2008, 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 2008 that
have materially affected, or are reasonably likely to materially affect,
internal controls over financial reporting.
While the Company's management, including the President and Chief
Operating Officer and the Chief Financial Officer and Senior
Vice-President, Finance believes that the Company's disclosure controls
and procedures and internal controls over financial reporting provide a
reasonable level of assurance they are effective, they recognize that all
control systems have inherent limitations. Because of its inherent
limitations, the Company's control systems 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, 2008, the Company adopted the following accounting
and disclosure standards issued by the CICA:
Capital Disclosures
o Section 1535 - "Capital Disclosures" requires entities to disclose
their objectives, policies and processes for managing capital, as
well as quantitative data about capital. The standard also requires
the disclosure of any externally imposed capital requirements and
compliance with those requirements. The standard does not define
capital. This standard affects disclosure only and did not impact
the Company's accounting for capital.
Inventories
o Section 3031 - "Inventories" replaces Section 3030 - "Inventories"
and establishes new standards for the measurement of cost of
inventories and expands disclosure requirements for inventories.
Adoption of this standard did not have a material impact on the
Company's financial statements.
Financial Instruments
o Section 3862 - "Financial Instruments - Disclosure" and Section
3863 "Financial Instruments - presentation" replace Section 3861 -
"Financial Instruments - Disclosure and Presentation". Section 3862
enhances disclosure requirements concerning risks and requires
quantitative and qualitative disclosures about exposures to risks
arising from financial instruments. Section 3863 carries forward
the presentation requirements from Section 3861 unchanged. These
standards affect disclosures only and did not impact the Company's
accounting for financial instruments.
Effective January 1, 2009, the Company will adopt the following new
accounting standard issued by the CICA:
Goodwill and Intangible Assets
o Section 3064 - "Goodwill and Intangible Assets" replaces Section
3062 - "Goodwill and Other Intangible Assets" and Section 3450 -
"Research and Development Costs." In addition, EIC-27 - "Revenue
and Expenditures during the Pre-Operating Period" has been
withdrawn. The new standard addresses when an internally generated
intangible asset meets the definition of an asset. Adoption of the
new standard may impact the Company's future capitalization of
certain costs during the development and start-up of large
development projects.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA's Accounting Standards Board confirmed that
Canadian publicly accountable enterprises will be required to adopt
International Financial Reporting Standards ("IFRS") as promulgated by
the International Accounting Standards Board ("IASB") in place of
Canadian GAAP effective January 1, 2011.
The Company commenced its IFRS conversion project in 2008 and has
established a formal project governance structure. The structure includes
a Steering Committee, which consists of senior levels of management from
finance and accounting, operations and information technology ("IT"). The
Steering Committee provides regular updates to the Company's Senior
Management and the Audit Committee of the Board of Directors.
66 CANADIAN NATURAL
The Company's IFRS conversion project consists of the following phases:
o Phase 1 Diagnostic - identification of potential accounting and
reporting differences between Canadian GAAP and IFRS.
o Phase 2 Planning - development of project governance, processes,
resources, budget and timeline.
o Phase 3 Policy Delivery and Documentation - establishment of
accounting policies under IFRS.
o Phase 4 Policy Implementation - establishment of processes for
accounting and reporting, IT change requirements, and education.
o Phase 5 Sustainment - ongoing compliance with IFRS after
implementation.
The Company has completed the Diagnostic phase. Significant differences
were identified in accounting for Property, Plant & Equipment ("PP&E"),
including exploration costs, depletion and depreciation, impairment
testing, capitalized interest and asset retirement obligations. Other
significant differences were noted in accounting for stock-based
compensation, risk management activities, and income taxes. The Company
is currently performing the necessary research to develop and document
IFRS policies to address the major differences noted. At this time, the
impact on the Company's future financial position and results of
operations is not reasonably determinable. In addition, IFRS is expected
to change prior to adoption in 2011, and the impact of these potential
changes is not known. Included in the potential IFRS changes is an
exposure draft issued in September 2008 by the IASB that proposes
transition rules for oil and gas companies following full cost
accounting. The proposed transition rule would allow full cost companies
to allocate their existing full cost PP&E balances using reserve values
or volumes to IFRS compliant units of account as at the date of
conversion without requiring retroactive adjustment. The Company intends
to adopt the transition rule if it is approved.
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 create shareholder value. Annual budgets are developed,
scrutinized throughout the year and revised if necessary in the context
of targeted financial ratios, 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 2009 to average between 331,000 bbl/d and 399,000
bbl/d of crude oil and NGLs and between 1,272 mmcf/d and 1,328 mmcf/d of
natural gas.
The forecasted capital expenditures in 2009 are currently expected to be
as follows:
-------------------------------------------------------------------------------
($ millions) 2009 Forecast
-------------------------------------------------------------------------------
Conventional crude oil and natural gas
North America natural gas $ 589
North America crude oil and NGLs 1,138
North Sea 141
Offshore West Africa 553
Property acquisitions, dispositions and midstream 109
-------------------------------------------------------------------------------
$ 2,530
-------------------------------------------------------------------------------
Horizon Project
Phase 1 - Construction $ 180
Phase 1 - Operating and capital inventory 43
Phase 1 - Commissioning costs 183
Phase 2/3 - Tranche 2 121
Sustaining capital 94
Capitalized interest and other costs 41
-------------------------------------------------------------------------------
$ 662
-------------------------------------------------------------------------------
Total $ 3,192
===============================================================================
North America Natural Gas
The 2009 North America natural gas drilling program is highlighted by the
continued high-grading of the Company's natural gas asset base as
follows:
-------------------------------------------------------------------------------
(Number of wells) 2009 Forecast
-------------------------------------------------------------------------------
Coal bed methane and shallow natural gas 30
Conventional natural gas 66
Cardium natural gas 9
Deep natural gas 37
-------------------------------------------------------------------------------
Total 142
===============================================================================
The Company has reduced 2009 natural gas drilling in Alberta due to the
anticipated future impact of royalty changes effective January 1, 2009.
CANADIAN NATURAL 67
North America Crude Oil and NGLs
The 2009 North America crude oil drilling program is highlighted by
continued development of the Primrose thermal projects, Pelican Lake, and
a strong conventional primary heavy program, as follows:
-------------------------------------------------------------------------------
(Number of wells) 2009 Forecast
-------------------------------------------------------------------------------
Conventional primary heavy crude oil 317
Thermal heavy crude oil 70
Light crude oil 20
Pelican Lake crude oil 58
-------------------------------------------------------------------------------
Total 465
===============================================================================
Horizon Project
During the initial stages of the ramp-up of production, the production
volumes will fluctuate on a weekly basis until the end of the second
quarter of 2009 when the Company expects to see a steady ramp up to full
production capacity of 110,000 bbl/d by the end of 2009. The Company will
work towards full capacity throughout 2009 as the plant continues to be
fine tuned to design rates with a focus on safety and reliability.
North Sea
The 2009 capital forecast for the North Sea includes drilling 0.9 net
platform wells with focus on building drilling and workover inventory for
2010.
Offshore West Africa
The 2009 capital forecast for anticipates spending $80 million to
complete Phase 2 of the development of the Baobab Field in Cote d'Ivoire.
The Company is targeting the fourth well to be completed in the second
quarter of 2009.
SENSITIVITY ANALYSIS
The following table is indicative of the annualized sensitivities of cash
flow from operations and net earnings from changes in certain key
variables. The analysis is based on business conditions and sales volumes
during the fourth quarter of 2008, excluding mark-to-market gains
(losses) on risk management activities and capitalized interest, and is
not necessarily indicative of future results. Each separate line item in
the sensitivity analysis shows the effect of a change in that variable
only with all other variables being held constant.
-----------------------------------------------------------------------------------------------------------------
CASH FLOW CASH FLOW
FROM FROM NET NET
OPERATIONS OPERATIONS EARNINGS EARNINGS
(per common (per common
($millions) share, basic) ($millions) share, basic)
-----------------------------------------------------------------------------------------------------------------
Price changes
Crude oil - WTI US$1.00/bbl (1)
Excluding financial derivatives $ 112 $ 0.21 $ 84 $ 0.16
Including financial derivatives $ 66 $ 0.12 $ 48 $ 0.09
Natural gas - AECO C$0.10/mcf (1)
Excluding financial derivatives $ 38 $ 0.07 $ 28 $ 0.05
Including financial derivatives $ 38 $ 0.07 $ 28 $ 0.05
Volume changes
Crude oil - 10,000 bbl/d $ 87 $ 0.16 $ 38 $ 0.07
Natural gas - 10 mmcf/d $ 18 $ 0.03 $ 7 $ 0.01
Foreign currency rate change
$0.01 change in US$ (1)
Including financial derivatives $ 89 - 92 $ 0.17 $ 8 - 9 $ 0.02
Interest rate change - 1% $ 32 $ 0.06 $ 32 $ 0.06
-----------------------------------------------------------------------------------------------------------------
(1) For details of financial instruments in place, refer to note 13 to
the Company's audited annual consolidated financial statements as
at December 31, 2008.
68 CANADIAN NATURAL
DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES
-----------------------------------------------------------------------------------------------------------|-----------------------
Q1 Q2 Q3 Q4 2008 | 2007 2006
-----------------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs (bbl/d) |
North America 248,960 245,616 239,973 240,831 243,826 | 246,779 235,253
North Sea 49,568 45,830 42,760 42,991 45,274 | 55,933 60,056
Offshore West Africa 28,689 27,631 24,237 25,748 26,567 | 28,520 36,689
-----------------------------------------------------------------------------------------------------------------------------------
Total 327,217 319,077 306,970 309,570 315,667 | 331,232 331,998
-----------------------------------------------------------------------------------------------------------------------------------
Natural gas (mmcf/d) |
North America 1,513 1,501 1,467 1,405 1,472 | 1,643 1,468
North Sea 11 10 9 10 10 | 13 15
Offshore West Africa 14 15 14 12 13 | 12 9
-----------------------------------------------------------------------------------------------------------------------------------
Total 1,538 1,526 1,490 1,427 1,495 | 1,668 1,492
-----------------------------------------------------------------------------------------------------------------------------------
Barrels of oil equivalent |
(boe/d) |
North America 501,061 495,836 484,542 475,089 489,081 | 520,564 479,891
North Sea 51,404 47,545 44,309 44,623 46,956 | 58,099 62,558
Offshore West Africa 31,023 30,056 26,505 27,687 28,808 | 30,543 38,275
-----------------------------------------------------------------------------------------------------------------------------------
Total 583,488 573,437 555,356 547,399 564,845 | 609,206 580,724
===================================================================================================================================
|
-----------------------------------------------------------------------------------------------------------|-----------------------
PER UNIT RESULTS (1) Q1 Q2 Q3 Q4 2008 | 2007 2006
-----------------------------------------------------------------------------------------------------------|-----------------------
Crude oil and NGLs ($/bbl)
Sales price (2) $ 78.99 $ 103.73 $ 102.30 $ 45.81 $ 82.41 | $ 55.45 $ 53.65
Royalties 8.70 14.82 14.17 4.49 10.48 | 5.94 4.48
Production expense 14.81 16.39 17.61 16.33 16.26 | 13.34 12.29
|
-----------------------------------------------------------------------------------------------------------|-----------------------
Netback $ 55.48 $ 72.52 $ 70.52 $ 24.99 $ 55.67 | $ 36.17 $ 36.88
-----------------------------------------------------------------------------------------------------------|-----------------------
Natural gas ($/mcf) |
Sales price (2) $ 7.77 $ 9.89 $ 8.82 $ 7.03 $ 8.39 | $ 6.85 $ 6.72
Royalties 1.35 1.86 1.55 1.08 1.46 | 1.11 1.29
Production expense 1.03 0.94 1.05 1.06 1.02 | 0.91 0.82
-----------------------------------------------------------------------------------------------------------|-----------------------
Netback $ 5.39 $ 7.09 $ 6.22 $ 4.89 $ 5.91 | $ 4.83 $ 4.61
-----------------------------------------------------------------------------------------------------------|-----------------------
Barrels of oil equivalent |
($/boe) |
Sales price (2) $ 65.09 $ 84.88 $ 80.60 $ 43.84 $ 68.62 | $ 49.05 $ 47.92
Royalties 8.43 13.26 12.06 5.37 9.78 | 6.26 5.89
Production expense 11.02 11.60 12.52 12.05 11.79 | 9.75 9.14
-----------------------------------------------------------------------------------------------------------|----------------------
Netback $ 45.64 $ 60.02 $ 56.02 $ 26.42 $ 47.05 | $ 33.04 $ 32.89
===================================================================================================================================
(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) 2008 | 2007 2006
---------------------------------------------------------------------------------------------|-------------------------------------
Sales price (2) $ 68.62 | $ 49.05 $ 47.92
Royalties 9.78 | 6.26 5.89
Production expense (3) 11.79 | 9.75 9.14
---------------------------------------------------------------------------------------------|-------------------------------------
Netback 47.05 | 33.04 32.89
Midstream contribution (3) (0.25) | (0.23) (0.23)
Administration 0.87 | 0.93 0.85
Interest, net 0.62 | 1.24 0.66
Realized risk management loss 8.99 | 0.73 6.27
Realized foreign exchange loss (0.55) | 0.24 (0.06)
(gain) |
Taxes other than income tax - 1.18 | 0.54 1.04
current |
Current income tax - North 0.15 | 0.43 0.68
America |
Current income tax - North Sea 1.64 | 0.95 0.14
Current income tax - Offshore 0.62 | 0.33 0.23
West Africa |
-----------------------------------------------------------------------------------------------------------------------------------
Cash flow $ 33.78 | $ 27.88 $ 23.31
===================================================================================================================================
(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.
CANADIAN NATURAL 69
TRADING AND SHARE STATISTICS
-----------------------------------------------------------------------------------------------------------|------------
Q1 Q2 Q3 Q4 2008 | 2007
-----------------------------------------------------------------------------------------------------------|------------
TSX - C$ |
Trading Volume (thousands) 134,421 145,018 186,906 213,393 679,738 | 429,034
Share Price ($/share) |
High $ 76.80 $ 111.30 $ 104.83 $ 72.89 $ 111.30 | $ 80.02
Low $ 58.88 $ 68.08 $ 64.40 $ 34.19 $ 34.19 | $ 52.45
Close $ 70.27 $ 100.84 $ 73.00 $ 48.75 $ 48.75 | $ 72.58
Market capitalization as at |
December 31 ($ millions) $ 26,373 | $ 39,174
|
Shares outstanding (thousands) 540,991 | 539,729
-----------------------------------------------------------------------------------------------------------|------------
NYSE - US$ |
Trading Volume (thousands) 157,781 190,756 292,659 326,032 967,228 | 486,266
Share Price ($/share) |
High $ 78.43 $ 109.32 $ 103.40 $ 68.87 $ 109.32 | $ 87.17
Low $ 57.07 $ 66.21 $ 61.82 $ 26.43 $ 26.43 | $ 44.56
Close $ 68.26 $ 100.25 $ 68.46 $ 39.98 $ 39.98 | $ 73.14
Market capitalization as at |
December 31($ millions) $ 21,629 | $ 39,476
Shares outstanding (thousands) 540,991 | 539,729
===========================================================================================================|============
70 CANADIAN NATURAL
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
M A N A G E M E N T ' S R E P O R T
The accompanying consolidated financial statements and all 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,
2008; and
o the effectiveness of the Company's internal control over financial
reporting as at December 31, 2008.
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 &
OPERATING OFFICER SENIOR VICE-PRESIDENT, ACCOUNTING
FINANCE
March 4, 2009
CALGARY, ALBERTA, CANADA
CANADIAN NATURAL 71
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
M A N A G E M E N T ' S A S S E S S M E N T O F I N T E R N A L
C O N T R O L O V E R F I N A N C I A L R E P O R T I N G
Management is responsible for establishing and maintaining adequate
internal control over financial reporting for the Company as defined in
rules 13a-15(f) and 15d-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, 2008. 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.
Pricewaterhousecoopers LLP, an independent firm of chartered accountants,
has provided an opinion on the Company's internal control over financial
reporting as at December 31, 2008, as stated in their auditors' report.
/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 4, 2009
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 integrated audits of Canadian Natural Resources
Limited's 2008, 2007, and 2006 consolidated financial statements and of
its internal control over financial reporting as at December 31, 2008.
Our opinions, based on our audits, are presented below.
CONSOLIDATED FINANCIAL STATEMENTS
We have audited the accompanying consolidated balance sheets of Canadian
Natural Resources Limited (the "Company") as at December 31, 2008 and
December 31, 2007, and the related consolidated statements of earnings,
shareholders' equity, comprehensive income and cash flows for each of the
years in the three year period ended December 31, 2008. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits of the Company's consolidated financial
statements in accordance with Canadian generally accepted auditing
standards and the standards of the public Company accounting oversight
Board (United States). 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. We believe that our audits provide a
reasonable basis for our opinion.
72 CANADIAN NATURAL
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the
Company as at December 31, 2008 and December 31, 2007 and the results of
its operations and its cash flows for each of the years in the three year
period ended December 31, 2008 in accordance with Canadian generally
accepted accounting principles.
INTERNAL CONTROL OVER FINANCIAL REPORTING
We have also audited Canadian Natural Resource Limited's internal control
over financial reporting as at December 31, 2008, 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, included in the accompanying Management's assessment of
internal control over Financial reporting. Our responsibility is to
express an opinion on 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, assessing
the risk that a material weakness exists, testing and evaluating the
design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we consider
necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
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, the Company maintained, in all material respects,
effective internal control over financial reporting as at December 31,
2008 based on criteria established in internal control - integrated
Framework issued by the COSO.
/s/PRICEWATERHOUSECOOPERS LLP
----------------------------------
CHARTERED ACCOUNTANTS
CALGARY, ALBERTA, CANADA
March 4, 2009
COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES
In the United States, reporting standards for auditors require the
addition of an explanatory paragraph (following the opinion paragraph)
when there is a change in accounting principles that has a material
effect on the comparability of the Company's consolidated financial
statements, such as the changes indicated in the Consolidated Statements
of Shareholders' Equity and Comprehensive Income. Our report to the
Shareholders dated March 4, 2009 is expressed in accordance with Canadian
reporting standards which do not require a reference to such a change in
accounting principles in the auditors' report when the change is properly
accounted for and adequately disclosed in the consolidated financial
statements.
/s/PRICEWATERHOUSECOOPERS LLP
----------------------------------
CHARTERED ACCOUNTANTS
CALGARY, ALBERTA, CANADA
March 4, 2009
CANADIAN NATURAL 73
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
C O N S O L I D A T E D B A L A N C E S H E E T S
As at December 31 |
(millions of Canadian dollars) 2008 | 2007
-------------------------------------------------------------------------------------------------|----------------
ASSETS |
Current assets |
Cash and cash equivalents $ 27 | $ 21
Accounts receivable and other 1,514 | 1,662
Future income tax (note 8) - | 480
Current portion of other long-term assets (note 3) 1,851 | 18
-------------------------------------------------------------------------------------------------|----------------
3,392 | 2,181
Property, plant and equipment (note 4) 38,966 | 33,902
Other long-term assets (note 3) 292 | 31
-------------------------------------------------------------------------------------------------|----------------
$ 42,650 | $ 36,114
-------------------------------------------------------------------------------------------------|----------------
LIABILITIES |
Current liabilities |
Accounts payable $ 383 | $ 379
Accrued liabilities 1,802 | 1,567
Future income tax (note 8) 585 | -
Current portion of long-term debt (note 5) 420 | -
Current portion of other long-term liabilities (note 6) 230 | 1,617
-------------------------------------------------------------------------------------------------|----------------
3,420 | 3,563
Long-term debt (note 5) 12,596 | 10,940
Other long-term liabilities (note 6) 1,124 | 1,561
Future income tax (note 8) 7,136 | 6,729
-------------------------------------------------------------------------------------------------|----------------
24,276 | 22,793
-------------------------------------------------------------------------------------------------|----------------
SHAREHOLDERS' EQUITY |
Share capital (note 9) 2,768 | 2,674
Retained earnings 15,344 | 10,575
Accumulated other comprehensive income (note 10) 262 | 72
-------------------------------------------------------------------------------------------------|----------------
18,374 | 13,321
-------------------------------------------------------------------------------------------------|----------------
$ 42,650 | $ 36,114
=================================================================================================|================
Commitments and contingencies (note 14).
Approved by the Board of Directors:
/s/Catherine M. Best N. Murray Edwards
----------------------------------- ------------------------------
Catherine M. Best N. Murray Edwards
CHAIR OF THE AUDIT COMMITTEE VICE-CHAIRMAN OF THE BOARD OF
AND DIRECTOR OF DIRECTORS
74 CANADIAN NATURAL
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
C O N S O L I D A T E D S T A T E M E N T O F E A R N I N G S
For the years ended December 31 |
(millions of Canadian dollars, except per common share amounts) 2008 | 2007 2006
-------------------------------------------------------------------------------------------|-----------------------------
Revenue $ 16,173 | $ 12,543 $ 11,643
Less: royalties (2,017) | (1,391) (1,245)
-------------------------------------------------------------------------------------------|-----------------------------
Revenue, net of royalties 14,156 | 11,152 10,398
-------------------------------------------------------------------------------------------|-----------------------------
Expenses |
Production 2,451 | 2,184 1,949
Transportation and blending 1,936 | 1,570 1,443
Depletion, depreciation and amortization 2,683 | 2,863 2,391
Asset retirement obligation accretion (note 6) 71 | 70 68
Administration 180 | 208 180
Stock-based compensation (recovery) expense (note 6) (52) | 193 139
Interest, net 128 | 276 140
Risk management activities (note 13) (1,230) | 1,562 312
Foreign exchange loss (gain) 718 | (471) 122
-------------------------------------------------------------------------------------------|-----------------------------
6,885 | 8,455 6,744
-------------------------------------------------------------------------------------------|-----------------------------
Earnings before taxes 7,271 | 2,697 3,654
Taxes other than income tax (note 8) 178 | 165 256
Current income tax expense (note 8) 501 | 380 222
Future income tax expense (recovery) (note 8) 1,607 | (456) 652
-------------------------------------------------------------------------------------------|-----------------------------
Net earnings $ 4,985 | $ 2,608 $ 2,524
===========================================================================================|=============================
Net earnings per common share (note 12) |
Basic and diluted $ 9.22 | $ 4.84 $ 4.70
===========================================================================================|=============================
CANADIAN NATURAL 75
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CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
C O N S O L I D A T E D S T A T E M E N T S O F
S H A R E H O L D E R S' E Q U I T Y
For the years ended December 31 |
(millions of Canadian dollars) 2008 | 2007 2006
-------------------------------------------------------------------------------------------|-----------------------------
Share capital |
Balance - beginning of year $ 2,674 | $ 2,562 $ 2,442
Issued upon exercise of stock options 18 | 21 21
Previously recognized liability on stock options exercised |
for common shares 76 | 91 101
Purchase of common shares under Normal Course Issuer Bid - | - (2)
-------------------------------------------------------------------------------------------|-----------------------------
Balance - end of year 2,768 | 2,674 2,562
-------------------------------------------------------------------------------------------|-----------------------------
Retained earnings |
Balance - beginning of year, as originally reported 10,575 | 8,141 5,804
Transition adjustment on adoption of financial instruments |
standards - | 10 -
-------------------------------------------------------------------------------------------|-----------------------------
Balance - beginning of year, as restated 10,575 | 8,151 5,804
Net earnings 4,985 | 2,608 2,524
Dividends on common shares (note 9) (216) | (184) (161)
Purchase of common shares under Normal Course Issuer Bid - | - (26)
-------------------------------------------------------------------------------------------|-----------------------------
Balance - end of year 15,344 | 10,575 8,141
-------------------------------------------------------------------------------------------|-----------------------------
Accumulated other comprehensive income (loss) |
Balance - beginning of year 72 | (13) (9)
Transition adjustment on adoption of financial instruments |
standards - | 159 -
-------------------------------------------------------------------------------------------|-----------------------------
Balance - beginning of year, after effect of transition |
adjustment 72 | 146 (9)
Other comprehensive income (loss), net of taxes 190 | (74) (4)
-------------------------------------------------------------------------------------------|-----------------------------
Balance - end of year 262 | 72 (13)
-------------------------------------------------------------------------------------------|-----------------------------
Shareholders' equity $ 18,374 | $ 13,321 $ 10,690
===========================================================================================|=============================
C O N S O L I D A T E D S T A T E M E N T S O F
C O M P R E H E N S I V E I N C O M E
For the years ended December 31 |
(millions of Canadian dollars) 2008 | 2007 2006
-------------------------------------------------------------------------------------------|-----------------------------
Net earnings $ 4,985 | $ 2,608 $ 2,524
-------------------------------------------------------------------------------------------|------------------------------
Net change in derivative financial instruments designated |
as cash flow hedges |
Unrealized income during the year, net of taxes of $1 30 | 38 -
million (2007 - $6 million, 2006 - $nil) |
Reclassification to net earnings, net of taxes of $6 (12) | (96) -
million (2007 - $45 million, 2006 - $nil) |
-------------------------------------------------------------------------------------------|------------------------------
18 | (58) -
Foreign currency translation adjustment |
Translation of net investment 172 | (16) (4)
-------------------------------------------------------------------------------------------|------------------------------
Other comprehensive income (loss), net of taxes 190 | (74) (4)
-------------------------------------------------------------------------------------------|------------------------------
Comprehensive income $ 5,175 | $ 2,534 $ 2,520
==========================================================================================================================
76 CANADIAN NATURAL
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S
For the years ended December 31 |
(millions of Canadian dollars) 2008 | 2007 2006
----------------------------------------------------------------------|---------------------------------
Operating activities |
Net earnings $ 4,985 | $ 2,608 $ 2,524
Non-cash items |
Depletion, depreciation and amortization 2,683 | 2,863 2,391
Asset retirement obligation accretion 71 | 70 68
Stock-based compensation (recovery) expense (52) | 193 139
Unrealized risk management (gain) loss (3,090) | 1,400 (1,013)
Unrealized foreign exchange loss (gain) 832 | (524) 134
Deferred petroleum revenue tax (recovery) |
expense (67) | 44 37
Future income tax expense (recovery) 1,607 | (456) 652
Other 25 | 38 (2)
Abandonment expenditures (38) | (71) (75)
Net change in non-cash working capital (note 15) (189) | (346) (679)
----------------------------------------------------------------------|---------------------------------
6,767 | 5,819 4,176
----------------------------------------------------------------------|---------------------------------
Financing activities |
(Repayment) issue of bank credit facilities, net (623) | (1,925) 6,499
Issue of medium-term notes - | 273 400
Repayment of senior unsecured notes (31) | (33) -
issue of US dollar debt securities 1,215 | 2,553 788
Issue of common shares on exercise of stock options 18 | 21 21
Dividends on common shares (208) | (178) (153)
Purchase of common shares - | - (28)
Net change in non-cash working capital (note 15) 46 | 8 37
----------------------------------------------------------------------|---------------------------------
417 | 719 7,564
----------------------------------------------------------------------|---------------------------------
Investing activities |
Expenditures on property, plant and equipment (7,433) | (6,464) (7,266)
Net proceeds on sale of property, plant and |
equipment 20 | 110 71
----------------------------------------------------------------------|---------------------------------
Net expenditures on property, plant and equipment (7,413) | (6,354) (7,195)
Acquisition of Anadarko Canada Corporation (note 16) - | - (4,641)
Net change in non-cash working capital (note 15) 235 | (186) 101
----------------------------------------------------------------------|---------------------------------
(7,178) | (6,540) (11,735)
----------------------------------------------------------------------|---------------------------------
Increase (Decrease) In Cash And Cash Equivalents 6 | (2) 5
Cash And Cash Equivalents - Beginning Of Year 21 | 23 18
----------------------------------------------------------------------|---------------------------------
Cash And Cash Equivalents - End Of Year $ 27 | $ 21 $ 23
======================================================================|=================================
Supplemental disclosure of cash flow information (note 15)
CANADIAN NATURAL 77
-------------------------------------------------------------------------------
CANADIAN NATURAL 2008 ANNUAL REPORT
-------------------------------------------------------------------------------
N O T E S T O T H E C O N S O L I D A T E D
F I N A N C I A L S T A T E M E N T S
(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 conventional
crude oil and natural gas operations are focused in North America, largely
in Western Canada; the United Kingdom ("UK") portion of the North Sea; and
Cote d'Ivoire and Gabon in Offshore West Africa.
Within Western Canada, the Company is developing its Horizon oil Sands
project (the "Horizon Project") in a series of staged development phases
("phases"). The Horizon Project is designed to produce synthetic crude oil
through bitumen mining and upgrading operations.
Also within Western Canada, the Company maintains certain midstream
activities that include 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 18.
Significant accounting policies are summarized as follows:
(A) PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company
and all of its 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 in impairment calculations are based on estimates of crude
oil and natural gas reserves. The estimation of reserves involves the
exercise of judgement. Forecasts are based on engineering data, estimated
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, and may be affected by changes in commodity prices. As a result,
the impact of differences between actual and estimated oil and gas
reserves amounts on the consolidated financial statements of future
periods may be material.
The calculation of asset retirement obligations includes estimates of the
future costs to settle the asset retirement obligation, the timing of the
cash flows to settle the obligation, and the future inflation rates. The
impact of differences between actual and estimated costs, timing and
inflation on the consolidated financial statements of future periods may
be material.
The calculation of income taxes requires judgement in applying tax laws
and regulations, estimating the timing of temporary difference reversals,
and estimating the realizability of future tax assets. These estimates
impact current and future income tax assets and liabilities, and current
and future income tax expense (recovery).
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 may result in material changes to deferred amounts.
The estimation of fair value for derivative financial instruments requires
the use of assumptions. In determining these assumptions, the Company has
relied primarily on external, readily observable market inputs including
quoted commodity prices and volatility, interest rate yield curves, and
foreign exchange rates. The resulting fair value estimates may not
necessarily be indicative of the amounts that could be realized or settled
in a current market transaction and these differences may be material.
(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.
78 CANADIAN NATURAL
(D) PROPERTY, PLANT AND EQUIPMENT
Conventional Crude Oil And Natural Gas
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") issued by the Canadian
Institute of Chartered Accountants ("CICA"). Accordingly, all costs
relating to the exploration for and development of conventional crude oil
and natural gas reserves are capitalized and accumulated in
country-by-country cost centres. Directly attributable administrative
overhead incurred during the development of certain 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 a gain or loss except where such dispositions
result in a change in the depletion rate of the specific cost centre of
20% or more.
Oil Sands Mining Operations And Upgrading Operations
The Company's Horizon Project is comprised of both mining operations and
upgrading operations and accordingly, capitalized costs related to the
Horizon Project are accounted for separately from the Company's Canadian
conventional crude oil and natural gas costs. Capitalized mining activity
costs include property acquisition, construction and development costs.
Construction and development costs are capitalized separately to each
phase of the Horizon Project. Construction and development for a
particular phase of the Horizon Project is considered complete once the
phase is available for its intended use. Costs related to major
maintenance turnaround activities will be capitalized and amortized on a
straight-line basis over the period to the next scheduled major
maintenance turnaround.
Midstream and Other
The Company capitalizes all costs that expand the capacity or extend the
useful life of the assets.
(E) OVERBURDEN REMOVAL COSTS
Overburden removal costs incurred during development of the Horizon
Project mine are capitalized to property, plant and equipment. Overburden
removal costs incurred during production of the Horizon Project mine will
be included in the cost of inventory produced, unless the overburden
removal activity has resulted in a betterment of the mineral property, in
which case the costs will be capitalized to property, plant and equipment.
Capitalized overburden removal costs will be amortized over the life of
the mining reserves that directly benefit from the overburden removal
activity.
(F) CAPITALIZED INTEREST
The Company capitalizes construction period interest based on the Horizon
Project costs incurred and the Company's cost of borrowing. Interest
capitalization on a particular phase of the Horizon Project ceases once
this phase is available for its intended use.
(G) LEASES
Contractual arrangements that meet the definition of a lease are accounted
for as capital leases or operating leases as appropriate. Leases that
transfer substantially all of the benefits and risks of ownership to the
Company are accounted for as capital leases and are recorded as property,
plant and equipment with an offsetting liability. All other leases are
accounted for as operating leases whereby lease costs are expensed as
incurred.
(H) DEPLETION, DEPRECIATION AND AMORTIZATION
Conventional Crude Oil And Natural Gas
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. Costs for major development projects, as identified
by management, are not subject to depletion until the projects are
available for their intended uses. Unproved properties and major
development projects are assessed periodically to determine whether
impairment has occurred. When proved reserves are assigned or the value of
an unproved property or major development project is considered to be
impaired, the cost of the property or the amount of the impairment is
added to costs subject to depletion. Processing and production facilities
are depreciated on a straight-line basis over their estimated lives.
The Company reviews the carrying amount of its conventional 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 expense 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.
Oil Sands Mining Operations And Upgrading Operations
Upon commencement of operations for the Horizon Project, mine-related
costs and costs of the upgrader and related infrastructure located on the
Horizon Project site will be amortized on the unit-of-production method
based on the estimated proved reserves of the Horizon Project or
productive capacity, respectively. Moveable mine-related equipment is
depreciated on a straight-line basis over its estimated useful life.
CANADIAN NATURAL 79
The Company reviews the carrying amount of the Horizon Project relative to
its recoverable amount if circumstances or events indicate impairment may
have occurred. The recoverable amount is calculated as the undiscounted
cash flow from the Horizon Project assets using proved and probable
reserves and expected future prices and costs. If the carrying amount
exceeds the recoverable amount, an impairment loss is recognized in
depletion equal to the amount by which the carrying amount of the assets
exceeds fair value. Fair value is calculated as the discounted cash flow
from the Horizon Project using proved and probable reserves and expected
future prices and costs.
Midstream and Other
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.
Other capital assets are amortized on a declining balance basis.
(I) ASSET RETIREMENT OBLIGATIONS
The Company provides for future asset retirement obligations on its
resource properties, facilities, production platforms, gathering systems,
and oil sands mining operations and tailings ponds 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 Horizon Project upgrader and related infrastructure and its
midstream 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.
(J) 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 accumulated
other comprehensive income (loss) 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 and foreign currency balances
are included in the consolidated statements of earnings.
(K) REVENUE RECOGNITION AND COSTS OF GOODS SOLD
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.
Related costs of goods sold are comprised of production; transportation
and blending; and depletion, depreciation and amortization expenses. These
amounts have been separately presented in the consolidated statements of
earnings.
(L) 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 statements of earnings.
(M) 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 oil and profit oil. Cost recovery oil allows
the Company to recover its capital and production costs and the costs
carried by the Company on behalf of the respective Government State oil
Companies (the "Governments"). Profit oil is allocated to the joint
venture partners in accordance with their respective equity interests,
after a portion has been allocated to the Governments. The Governments'
share of profit oil attributable to the Company's equity interest is
allocated to royalty expense and current income tax expense in accordance
with the terms of the PSCs.
80 CANADIAN NATURAL
(N) PETROLEUM REVENUE TAX
The Company accounts for the UK petroleum revenue tax ("PRT") by the
life-of-the-field method. The total future liability or recovery of PRT is
estimated using proved and probable reserves and anticipated future 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.
(O) 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 or 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 arising from the conventional crude oil and natural gas
business in Canada is primarily generated through partnerships, with the
related income taxes payable in subsequent periods. Accordingly, north
america current and future income taxes have been provided on the basis of
this corporate structure.
(P) 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 a 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, after consideration of 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
capitalized during the construction period in the case of the Horizon
Project. When stock options are surrendered for cash, the cash settlement
paid reduces the outstanding liability. When stock options are exercised
for common shares under the Option Plan, consideration paid by employees
and any previously recognized liability associated with the stock options
are recorded as share capital.
The Company has an employee stock savings plan and a stock bonus plan.
Contributions to the employee stock savings plan are recorded as
compensation expense at the time of the contribution. Contributions to the
stock bonus plan are recognized as compensation expense over the related
vesting period.
(Q) FINANCIAL INSTRUMENTS
The Company classifies its financial instruments into one of the following
categories: held-for-trading financial assets and financial liabilities;
held-to-maturity investments, loans and receivables; available-for-sale
financial assets; and other financial liabilities. All financial
instruments are required to be measured at fair value on initial
recognition. Measurement in subsequent periods is dependent on the
classification of the respective financial instrument.
Held-for-trading financial instruments are subsequently measured at fair
value with changes in fair value recognized in net earnings.
Available-for-sale financial assets are subsequently measured at fair
value with changes in fair value recognized in other comprehensive income,
net of tax. All other categories of financial instruments are measured at
amortized cost using the effective interest method.
Cash and cash equivalents are classified as held-for-trading and are
measured at fair value. Accounts receivable are classified as loans and
receivables. Accounts payable, accrued liabilities, certain other
long-term liabilities, and long-term debt are classified as other
financial liabilities. Although the Company does not intend to trade its
derivative financial instruments, risk management assets and liabilities
are classified as held-for-trading for accounting purposes unless formally
designated as hedges.
Transaction costs that are directly attributable to the acquisition or
issue of a financial asset or financial liability and original issue
discounts on long-term debt have been included in the carrying value of
the related financial asset or liability and are amortized to consolidated
net earnings over the life of the financial instrument using the effective
interest method.
(R) RISK MANAGEMENT ACTIVITIES
The Company uses derivative financial instruments to manage its commodity
price, foreign currency and interest rate exposures. These financial
instruments are entered into solely for hedging purposes and are not used
for speculative purposes.
Effective January 1, 2007, all derivative financial instruments are
recognized on the consolidated balance sheet at estimated fair value at
each balance sheet date. The estimated fair value of derivative financial
instruments is determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values determined using
valuation models require the use of assumptions concerning the amount and
timing of future cash flows and discount rates.
The Company documents all derivative financial instruments that are
formally 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.
CANADIAN NATURAL 81
The Company periodically 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. The effective portion
of changes in the fair value of derivative commodity price contracts
formally designated as cash flow hedges is initially recognized in other
comprehensive income and is reclassified to risk management activities in
consolidated net earnings in the same period or periods in which the crude
oil or natural gas is sold. The ineffective portion of changes in the fair
value of these designated contracts is immediately recognized in risk
management activities in consolidated net earnings. All changes in the
fair value of non-designated crude oil and natural gas commodity price
contracts are recognized in risk management activities in consolidated net
earnings.
The Company enters into interest rate swap contracts to manage its fixed
to floating interest rate mix on certain of its 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. Changes in the fair value of interest rate swap
contracts designated as fair value hedges and corresponding changes in the
fair value of the hedged long-term debt are included in interest expense
in consolidated net earnings. Changes in the fair value of non-designated
interest rate swap contracts are included in risk management activities in
consolidated net earnings.
Cross currency swap contracts are periodically used to manage currency
exposure on us dollar denominated long-term debt. The cross currency swap
contracts require the periodic exchange of payments with the exchange at
maturity of notional principal amounts on which the payments are based.
Changes in the fair value of the foreign exchange component of cross
currency swap contracts designated as cash flow hedges are included in
foreign exchange in consolidated net earnings. The effective portion of
changes in the fair value of the interest rate component of cross currency
swap contracts designated as cash flow hedges is initially included in
other comprehensive income and is reclassified to interest expense when
realized, with the ineffective portion recognized in risk management
activities in consolidated net earnings. Changes in the fair value of
non-designated cross currency swap contracts are included in risk
management activities in consolidated net earnings.
Realized gains or losses on the termination of financial instruments that
have been designated as cash flow hedges are deferred under accumulated
other comprehensive income on the consolidated balance sheets and
amortized into consolidated net earnings in the period in which the
underlying hedged item 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 consolidated net earnings. Realized gains or
losses on the termination of financial instruments that have not been
designated as hedges are recognized in consolidated net earnings
immediately.
Upon termination of an interest rate swap designated as a fair value
hedge, the interest rate swap is de-recognized on the balance sheet and
the related long-term debt hedged is no longer revalued for changes in
fair value. The fair value adjustment on the long-term debt at the date of
termination of the interest rate swap is amortized to interest expense
over the remaining term of the debt.
Foreign currency forward contracts are periodically used to manage foreign
currency cash management requirements. The foreign currency forward
contracts involve the purchase or sale of an agreed upon amount of US
dollars at a specified future date at forward exchange rates. Changes in
the fair value of the foreign currency forward contracts are included in
risk management activities in consolidated net earnings.
Embedded derivatives are derivatives that are included in a non-derivative
host contract. Embedded derivatives are recorded at fair value separately
from the host contract when their economic characteristics and risks are
not clearly and closely related to the host contract.
(S) COMPREHENSIVE INCOME
Comprehensive income is comprised of the Company's net earnings and other
comprehensive income. Other comprehensive income includes the effective
portion of changes in the fair value of derivative financial instruments
designated as cash flow hedges and foreign currency translation gains and
losses on the net investment in self-sustaining foreign operations. Other
comprehensive income is shown net of related income taxes.
(T) 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 the calculation of 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.
82 CANADIAN NATURAL
(U) RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP
Effective January 1, 2009, the Company will adopt the following new
accounting standard issued by the CICA:
Goodwill and Intangible Assets
o Section 3064 - "Goodwill and Intangible Assets" replaces Section 3062
- "Goodwill and Other Intangible Assets" and Section 3450 - "Research
and Development Costs". In addition, EIC-27 - "Revenue and
Expenditures During the Pre-operating Period" has been withdrawn. The
new standard addresses when an internally generated intangible asset
meets the definition of an asset. The adoption of this standard will
not have a material impact on the Company's financial statements.
(V) INTERNATIONAL FINANCIAL REPORTING STANDARDS
In February 2008, the CICA's accounting Standards Board confirmed that
Canadian publicly accountable entities will be required to adopt
International Financial Reporting Standards ("IFRS") as promulgated by the
international accounting Standards Board in place of Canadian GAAP
effective January 1, 2011. The Company is currently assessing which
accounting policies will be affected by the change to IFRS and the
potential impact of these changes on its financial position and results of
operations.
(W) COMPARATIVE FIGURES
Certain prior year figures have been reclassified to conform to the
presentation adopted in 2008.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2008, the Company adopted the following new
accounting and disclosure standards issued by the CICA:
o Section 1535 - "Capital Disclosures" requires entities to disclose
their objectives, policies and processes for managing capital, as
well as quantitative data about capital. The standard also requires
the disclosure of any externally imposed capital requirements and
compliance with those requirements. The standard does not define
capital. This standard affected disclosure only and did not impact
the Company's accounting for capital (note 11).
o Section 3031 - "Inventories" replaces Section 3030 - "Inventories"
and establishes new standards for the measurement of cost of
inventories and expands disclosure requirements for inventories.
Adoption of this standard did not have a material impact on the
Company's financial statements.
o Section 3862 - "Financial Instruments - Disclosure" and Section 3863
- "Financial Instruments - Presentation" replace Section 3861 -
"Financial Instruments - Disclosure and Presentation". Section 3862
enhances disclosure requirements concerning risks and requires
quantitative and qualitative disclosures about exposures to risks
arising from financial instruments. Section 3863 carries forward the
presentation requirements from Section 3861 unchanged. These
standards affected disclosures only and did not impact the Company's
accounting for financial instruments (note 13).
3. OTHER LONG-TERM ASSETS
2008 | 2007
----------------------------------------------------------------------------------------|-----------------
Risk management (note 13) $ 2,119 | $ -
Other 24 | 49
----------------------------------------------------------------------------------------|-----------------
2,143 | 49
Less: current portion 1,851 | 18
----------------------------------------------------------------------------------------|-----------------
$ 292 | $ 31
========================================================================================|=================
4. PROPERTY, PLANT AND EQUIPMENT
2008 | 2007
-----------------------------------------------------------------|----------------------------------------
Cost Net | Cost Net
Accumulated | Accumulated
depletion | depletion
and | and
depreciation | depreciation
-----------------------------------------------------------------|----------------------------------------
Conventional crude oil |
and natural gas
North America $ 36,532 $ 14,381 $ 22,151 | $ 34,195 $ 12,162 $ 22,033
North Sea 4,167 2,119 2,048 | 3,174 1,446 1,728
Offshore West Africa 2,671 777 1,894 | 1,833 645 1,188
Other 40 14 26 | 39 14 25
Horizon Project 12,573 - 12,573 | 8,651 - 8,651
Midstream 278 72 206 | 269 64 205
Head office 190 122 68 | 170 98 72
-----------------------------------------------------------------|----------------------------------------
$ 56,451 $ 17,485 $ 38,966 | $ 48,331 $ 14,429 $ 33,902
=================================================================|========================================
During the year ended December 31, 2008, the Company capitalized directly
attributable administrative costs of $55 million (2007 - $47 million, 2006
- $41 million) in the North Sea and Offshore West Africa, related to
exploration and development and$404 million (2007 - $312 million, 2006 -
$255 million) in North America, related to the Horizon Project
construction.
During the year ended December 31, 2008, the Company capitalized $481
million (2007 - $356 million, 2006 - $196 million) in construction period
interest costs related to the Horizon Project.
CANADIAN NATURAL 83
Included in property, plant and equipment are unproved land and major
development projects that are not currently subject to depletion or
depreciation:
2008 | 2007
-----------------------------------------------------------------------------------------------------------|----------------
Conventional crude oil and natural gas |
North America $ 2,271 | $ 2,259
North Sea 12 | 10
Offshore West Africa 595 | 138
Other 26 | 25
Horizon Project 12,573 | 8,651
-----------------------------------------------------------------------------------------------------------|----------------
$ 15,477 | $ 11,083
===========================================================================================================|================
The Company has used the following estimated benchmark future prices
("escalated pricing") in its full cost ceiling tests for conventional
crude oil and natural gas activities prepared in accordance with Canadian
GAAP, as at December 31, 2008:
Average
annual
increase
2009 2010 2011 2012 2013 thereafter
---------------------------------------------------------------------------------------------------------------------------
Crude oil and NGLs
North America
WTI at cushing (US$/bbl) $ 53.73 $ 63.41 $ 69.53 $ 79.59 $ 92.01 2.0%
Hardisty Heavy 12(degree) API (C$/bbl) $ 47.05 $ 54.58 $ 59.96 $ 67.53 $ 74.08 2.0%
Edmonton Par (C$/bbl) $ 65.35 $ 72.78 $ 79.95 $ 86.57 $ 94.97 2.0%
North Sea and Offshore West Africa
North Sea Brent (US$/bbl) $ 51.73 $ 61.37 $ 67.45 $ 77.47 $ 89.84 2.0%
---------------------------------------------------------------------------------------------------------------------------
Natural gas
North America
Henry Hub Louisiana (US$/mmbtu) $ 6.30 $ 7.32 $ 7.56 $ 8.49 $ 9.74 2.0%
AECO (C$/mmbtu) $ 6.82 $ 7.56 $ 7.84 $ 8.38 $ 9.20 2.2%
Huntingdon/Sumas (C$/mmbtu) $ 6.82 $ 7.56 $ 7.84 $ 8.38 $ 9.20 2.2%
===========================================================================================================================
84 CANADIAN NATURAL
5. Long-term debt
2008 2007
--------------------------------------------------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities
Bankers' acceptances $ 4,073 $ 4,696
Medium-term notes
5.50% unsecured debentures due December 17, 2010 400 400
4.50% unsecured debentures due January 23, 2013 400 400
4.95% unsecured debentures due June 1, 2015 400 400
--------------------------------------------------------------------------------------------------------------------
5,273 5,896
--------------------------------------------------------------------------------------------------------------------
US dollar denominated debt
Senior unsecured notes
Adjustable rate due May 27, 2009 (2008 - US$31 million, 2007 - US$62 million) 38 61
US dollar debt securities
7.80% due July 2, 2008 (2008 - US$nil, 2007 - US$8 million) - 8
6.70% due July 15, 2011 (2008 - US$400 million, 2007 - US$400 million) 490 395
5.45% due October 1, 2012 (2008 - US$350 million, 2007 - US$350 million) 429 346
5.15% due February 1, 2013 (2008 - US$400 million, 2007 - US$nil) 490 -
4.90% due December 1, 2014 (2008 - US$350 million, 2007 - US$350 million) 429 346
6.00% due August 15, 2016 (2008 - US$250 million, 2007 - US$250 million) 306 247
5.70% due May 15, 2017 (2008 - US$1,100 million, 2007 - US$1,100 million) 1,346 1,087
5.90% due February 1, 2018 (2008 - US$400 million, 2007 - US$nil) 490 -
7.20% due January 15, 2032 (2008 - US$400 million, 2007 - US$400 million) 490 395
6.45% due June 30, 2033 (2008 - US$350 million, 2007 - US$350 million) 429 346
5.85% due February 1, 2035 (2008 - US$350 million, 2007 - US$350 million) 429 346
6.50% due February 15, 2037 (2008 - US$450 million, 2007 - US$450 million) 551 445
6.25% due March 15, 2038 (2008 - US$1,100 million, 2006 - US$1,100 million) 1,346 1,087
6.75% due February 1, 2039 (2008 - US$400 million, 2007 - US$nil) 490 -
Less - original issue discount on senior unsecured notes and US dollar (23) (23)
debt securities (1)
--------------------------------------------------------------------------------------------------------------------
7,730 5,086
Fair value impact of interest rate swaps on US dollar debt securities (2) 68 9
--------------------------------------------------------------------------------------------------------------------
7,798 5,095
--------------------------------------------------------------------------------------------------------------------
Long-term debt before transaction costs 13,071 10,991
Less: transaction costs (1) (3) (55) (51)
--------------------------------------------------------------------------------------------------------------------
13,016 10,940
Less: current portion 420 -
--------------------------------------------------------------------------------------------------------------------
$ 12,596 $ 10,940
====================================================================================================================
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying value of the
outstanding debt.
(2) The carrying value of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been
adjusted by $68 million (2007 - $9 million) to reflect the fair value
impact of hedge accounting.
(3) Transaction costs primarily represent underwriting commissions
charged as a percentage of the related debt offerings, as well as
legal, rating agency and other professional fees.
Bank Credit Facilities
As at December 31, 2008, the Company had in place unsecured bank credit
facilities of $6,232 million, comprised of:
o a $125 million demand credit facility;
o a non-revolving syndicated credit facility of $2,350 million maturing
October 2009;
o a revolving syndicated credit facility of $2,230 million maturing
June 2012;
o a revolving syndicated credit facility of $1,500 million maturing
June 2012; and
o a (pound)15 million demand credit facility related to the Company's
North Sea operations.
During 2007, one of the revolving syndicated credit facilities was
increased from $1,825 million to $2,230 million and a $500 million demand
credit facility was terminated. The revolving syndicated credit facilities
were also extended and now mature June 2012. 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 will be repayable on the maturity
date. Borrowings under these facilities can be made by way of Canadian
dollar and US dollar bankers' acceptances, and LIBOR, US Base Rate And
Canadian Prime Loans.
In Conjunction with the closing of the acquisition of Anadarko Canada
Corporation ("ACC") in November 2006 (note 16), the Company executed a
$3,850 million, non-revolving syndicated credit facility maturing in
October 2009. In March 2007, $1,500 million was repaid, reducing the
facility to $2,350 million. During 2009, the Company plans to fully retire
this facility from its existing borrowing capacity under its other
long-term bank credit facilities, which were $2,050 million at December 31,
2008,
CANADIAN NATURAL 85
supported by cash flow from operating activities, including the commodity
risk management activities. In accordance with these plans, and repayments
of $420 million made subsequent to December 31, 2008 on this facility, $420
million has been classified as current.
The weighted average interest rate of the bank credit facilities
outstanding at December 31, 2008, was 2.2% (2007 - 5.2%).
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $372 million, including $300 million related to the
Horizon Project, were outstanding at December 31, 2008.
Medium-term Notes
The Company has $2,600 million remaining on its outstanding $3,000 million
base shelf prospectus filed in September 2007 that allows for the issue of
medium-term notes in Canada until October 2009. If issued, these
securities will bear interest as determined at the date of issuance.
In December 2007, the Company issued $400 million of unsecured notes
maturing December 2010, bearing interest at 5.50%. Proceeds from the
Securities issued were used to repay bankers' acceptances under the
Company's bank credit facilities.
During 2007, $125 million of 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%, with
the final annual principal repayment of US$31 million due in May 2009.
During 2008, US$31 million of the senior unsecured notes were repaid.
US Dollar Debt Securities
In January 2008, the Company issued US$1,200 million of unsecured notes
under a US base shelf prospectus, comprised of US$400 million of 5.15%
unsecured notes due February 2013, US$400 million of 5.90% unsecured notes
due February 2018, and US$400 million of 6.75% unsecured notes due
February 2039. 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 US$1,800 million remaining on
its outstanding US$3,000 million base shelf prospectus filed in September
2007 that allows for the issue of US dollar debt securities in the United
States until October 2009. If issued, these securities will bear interest
as determined at the date of issuance.
During 2008, US$8 million of US dollar debt securities were repaid.
In March 2007, the Company issued US$2,200 million of unsecured notes,
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 swaps to fix the Canadian dollar interest and principal
repayment amounts on the entire US$1,100 million of unsecured notes due
May 2017 at 5.10% and C$1,287 million (note 13). The Company also entered
into a cross currency 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 (note 13). Proceeds from the securities
issued were used to repay bankers' acceptances under the Company's bank
credit facilities.
During 2008, the Company terminated the interest rate swaps that had been
designated as a fair value hedge of US$350 million of 5.45% unsecured
notes due October 2012. Accordingly, the Company ceased revaluing the
related debt from the date of termination of the interest rate swaps for
subsequent changes in fair value. The fair value adjustment of $20 million
at the date of termination is being amortized to interest expense over the
remaining term of the debt.
During 2007, the Company de-designated the portion of the US dollar
denominated debt previously hedged against its net investment in US dollar
based self-sustaining foreign operations. Accordingly, all foreign
exchange (gains) losses arising each period on US dollar denominated
long-term debt are now recognized in the consolidated statements of
earnings.
Required Debt Repayments
Required debt repayments are as follows:
Year Repayment
---------------------------------------------------------------------------
2009 $ 2,385
2010 $ 400
2011 $ 490
2012 $ 429
2013 $ 890
Thereafter $ 6,707
===========================================================================
No debt repayments are reflected in the above table for $1,725 million of
revolving bank credit facilities due to the extendable nature of the
facilities. Should the bank credit facilities not be extended by mutual
agreement of the Company and the lenders, the entire amounts due under
these facilities would be due in 2012.
86 CANADIAN NATURAL
6. OTHER LONG-TERM LIABILITIES
2008 | 2007
------------------------------------------------------------------|---------------
Asset retirement obligations $ 1,064 | $ 1,074
Stock-based compensation 171 | 529
Risk management (note 13) - | 1,474
Other 119 | 101
------------------------------------------------------------------|---------------
1,354 | 3,178
Less: current portion 230 | 1,617
------------------------------------------------------------------|---------------
$ 1,124 | $ 1,561
==================================================================|===============
Asset Retirement Obligations
At December 31, 2008, the Company's total estimated undiscounted costs to
settle its asset retirement obligations were approximately $4,474 million
(2007 - $4,426 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 a weighted average credit-adjusted
risk-free interest rate of 6.7% (2007 - 6.6%; 2006 - 6.7%). A
reconciliation of the discounted asset retirement obligations is as
follows:
2008 | 2007 2006
------------------------------------------------------------------|-------------------------------
Balance - beginning of year $ 1,074 | $ 1,166 $ 1,112
Liabilities incurred 18 | 21 26
Liabilities acquired (note16) 3 | - 56
Liabilities disposed - | (65) -
Liabilities settled (38)| (71) (75)
Asset retirement obligation accretion 71 | 70 68
Revision of estimates (156)| 35 (21)
Foreign exchange 92 | (82) -
------------------------------------------------------------------|-------------------------------
Balance - end of year $ 1,064 | $ 1,074 $ 1,166
==================================================================|===============================
Stock-based compensation
The Company recognizes a liability for 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.
2008 | 2007 2006
------------------------------------------------------------------|-------------------------------
Balance - beginning of year $ 529 | $ 744 $ 891
Stock-based compensation (52)| 193 139
Cash payment for options surrendered (207)| (375) (264)
Transferred to common shares (76)| (91) (101)
Capitalized to Horizon Project (23)| 58 79
------------------------------------------------------------------|-------------------------------
Balance - end of year 171 | 529 744
Less: current portion 159 | 390 611
------------------------------------------------------------------|-------------------------------
$ 12 | $ 139 $ 133
==================================================================|===============================
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 7.0% (2007 - 5.5%) 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,
2008 was $27 million (2007 - $32 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, 2008, these plan
assets had a fair value of $34 million (2007 - $47 million). The
unregistered pension plan and other post-retirement benefits are unfunded
and have a benefit obligation of $9 million at December 31, 2008 (2007 -
$10 million).
CANADIAN NATURAL 87
8. TAXES
Taxes Other Than Income Tax
2008 | 2007 2006
----------------------------------------------------------------|----------------------------------
Current PRT expense $ 210 | $ 97 $ 196
Deferred PRT (recovery) expense (67)| 44 37
Provincial capital taxes and surcharges 35 | 24 23
----------------------------------------------------------------|----------------------------------
$ 178 | $ 165 $ 256
================================================================|==================================
Income Tax
The provision for income tax is as follows:
2008 | 2007 2006
----------------------------------------------------------------|----------------------------------
Current income tax - North America $ 33 | $ 96 $ 143
Current income tax - North Sea 340 | 210 30
Current income tax - Offshore West Africa 128 | 74 49
----------------------------------------------------------------|----------------------------------
Current income tax expense 501 | 380 222
Future income tax expense (recovery) 1,607 | (456) 652
----------------------------------------------------------------|----------------------------------
Income tax expense (recovery) $ 2,108 | $ (76) $ 874
================================================================|==================================
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:
2008 | 2007 2006
----------------------------------------------------------------|-----------------------------------
Canadian statutory income tax rate 29.8%| 32.5% 34.9%
----------------------------------------------------------------|-----------------------------------
Income tax provision at statutory rate $ 2,166 | $ 877 $ 1,275
Effect on income taxes of: |
Non-deductible portion of Canadian crown |
payments - | - 131
Canadian resource allowance - | - (129)
Deductible UK petroleum revenue tax (72)| (71) (82)
Foreign and domestic tax rate differentials (5)| (25) 6
North America income tax rate and other |
legislative changes (19)| (864) (438)
UK income tax rate changes - | - 110
Cote d'Ivoire income tax rate changes (22)| - (67)
Non-taxable portion of foreign exchange loss |
(gain) 127 | (96) 5
Stock options exercised in shares 6 | 63 35
Other (73)| 40 28
----------------------------------------------------------------|-----------------------------------
Income tax expense (recovery) $ 2,108 | $ (76) $ 874
=================================================================|==================================
The following table summarizes the temporary differences that give rise to
the net future income tax asset and liability:
2008 | 2007
----------------------------------------------------------------------------------|-----------------
Future income tax liabilities
Property, plant and equipment $ 6,303 | $ 5,695
Timing of partnership items 1,276 | 1,288
Unrealized foreign exchange gain on long-term debt 13 | 199
Unrealized risk management activities 651 | -
Other - | 55
Future income tax assets |
Asset retirement obligations (372)| (380)
Loss carryforwards for income tax (62)| (104)
Stock-based compensation (38)| (125)
Unrealized risk management activities - | (399)
Other (7)| -
Deferred petroleum revenue tax (43)| 20
----------------------------------------------------------------------------------|-----------------
Net future income tax liability 7,721 | 6,249
Less: current portion of future income tax liability (asset) 585 | (480)
----------------------------------------------------------------------------------|-----------------
Future income tax liability $ 7,136 | $ 6,729
==================================================================================|=================
During 2008, substantively enacted or enacted income tax rate changes
resulted in a reduction of future income tax liabilities of approximately
$19 million in British Columbia and approximately $22 million in Cote
d'Ivoire.
During 2007, substantively enacted or enacted income tax rate and other
legislative changes resulted in a reduction of future income tax
liabilities of approximately $864 million in North America.
88 CANADIAN NATURAL
During 2006, enacted 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 2003, the Canadian Federal Government enacted legislation to phase
in changes to the taxation of resource income by 2007. The legislation
reduced the corporate income tax rate on resource income to 21%, the
deduction for resource allowance was phased out and a deduction for actual
crown royalties paid was phased in. Subsequently, as a result of enacted
income tax rate changes in 2007, the Canadian Federal corporate income tax
rate is being reduced from 21% in 2007 to 15% in 2012.
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
2008 | 2007
--------------------------------------------------------------------------|----------------------------------
Common shares Number of Amount | Number of Amount
shares | shares
(thousands) | (thousands)
--------------------------------------------------------------------------|----------------------------------
Balance - beginning of year 539,729 $ 2,674 | 537,903 $ 2,562
Issued upon exercise of stock options 1,262 18 | 1,826 21
Previously recognized liability on |
stock options exercised for common shares - 76 | - 91
--------------------------------------------------------------------------|----------------------------------
Balance - end of year 540,991 $ 2,768 | 539,729 $ 2,674
==========================================================================|==================================
Normal Course Issuer Bid
The Company did not renew the Normal Course Issuer Bid during 2008. During
2007 and 2008, the Company did not purchase any common shares for
cancellation (2006 - 485,000 common shares were purchased at an average
price of $57.33 per common share for a total cost of $28 million).
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 2009, the Board of Directors set the Company's regular quarterly
dividend at $0.105 per common share (2008 - $0.10 per common share, 2007 -
$0.085 per common share).
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 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 of the option.
The following table summarizes information relating to stock options
outstanding at December 31, 2008 and 2007:
2008 | 2007
--------------------------------------------------------------------------|----------------------------------
Weighted | Weighted
Stock average | Stock average
options exercise | options exercise
(thousands) price | (thousands) price
--------------------------------------------------------------------------|----------------------------------
Outstanding - beginning of year 30,659 $ 47.23 | 34,431 $ 33.77
Granted 7,705 $ 53.38 | 7,502 $ 70.03
Surrendered for cash settlement (3,702) $ 25.60 | (7,249) $ 16.10
Exercised for common shares (1,262) $ 14.61 | (1,826) $ 11.71
Forfeited (2,438) $ 56.56 | (2,199) $ 46.46
--------------------------------------------------------------------------|----------------------------------
Outstanding - end of year 30,962 $ 51.94 | 30,659 $ 47.23
--------------------------------------------------------------------------|----------------------------------
Exercisable - end of year 8,809 $ 44.58 | 7,640 $ 30.00
==========================================================================|==================================
CANADIAN NATURAL 89
The range of exercise prices of stock options outstanding and exercisable
at December 31, 2008 was as follows:
Stock options outstanding Stock options exercisable
--------------------------------------------------------------------------------------------------------------
Weighted
Stock average Weighted Stock Weighted
options remaining average options average
outstanding term exercise exercisable exercise
Range of exercise prices (thousands) (years) price (thousands) price
---------------------------------------------------------------------------------------------------------------
$11.83 - $19.99 2,909 0.51 $ 16.44 1,918 $ 16.13
$20.00 - $29.99 3,023 1.30 $ 25.57 1,454 $ 25.42
$30.00 - $39.99 865 1.66 $ 33.27 397 $ 33.30
$40.00 - $49.99 6,845 5.01 $ 46.37 203 $ 46.29
$50.00 - $59.99 5,001 2.75 $ 58.06 1,860 $ 57.93
$60.00 - $69.99 4,884 3.15 $ 61.54 1,762 $ 61.60
$70.00 - $79.99 6,526 4.20 $ 70.76 1,215 $ 70.67
$80.00 - $89.99 - - $ - - $ -
$90.00 - $92.50 909 5.53 $ 92.50 - $ -
---------------------------------------------------------------------------------------------------------------
30,962 3.32 $ 51.94 8,809 $ 44.58
===============================================================================================================
10. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of taxes,
were as follows:
2008 | 2007
----------------------------------------------------------------------------------------------|-----------------
Derivative financial instruments designated as cash flow hedges $ 119 | $ 101
Foreign currency translation adjustment 143 | (29)
----------------------------------------------------------------------------------------------|-----------------
$ 262 | $ 72
==============================================================================================|=================
During the next twelve months, $19 million is expected to be reclassified
to net earnings from accumulated other comprehensive income.
During 2008, the Company determined that its operations in Offshore West
Africa were now operationally and financially independent and the current
rate method of translation was adopted for translation of the financial
statements of the Offshore West African subsidiaries. This change has been
applied prospectively. The impact of this change was to increase assets by
$32 million, decrease liabilities by $4 million and increase accumulated
other comprehensive income by $36 million.
11. CAPITAL DISCLOSURES
As required by Canadian GAAP, effective January 1, 2008, the Company must
provide certain disclosures regarding its objectives, policies and
processes for managing capital, as well as provide certain quantitative
data about capital. As the Company does not have any externally imposed
regulatory capital requirements, for the purposes of this disclosure, the
Company has defined its capital to mean its long-term debt and
consolidated shareholders' equity, as determined each reporting date.
The Company's objectives when managing its capital structure are to
maintain financial flexibility and balance to enable the Company to access
capital markets to sustain its on-going operations and to support its
growth strategies. The Company primarily monitors capital on the basis of
an internally derived non-GAAP financial measure referred to as its "debt
to book capitalization ratio", which is the arithmetic ratio of current
and long-term debt divided by the sum of the carrying value of
shareholders' equity plus current and long-term debt. The Company aims
over time to maintain its debt to book capitalization ratio in the range
of 35% to 45%. However, the Company may exceed the high end of such target
range if it is investing in capital projects, undertaking acquisitions, or
in periods of lower commodity prices. The Company may be below the low end
of the target range when cash flow from operating activities is greater
than current investment activities. The ratio is currently near the
midpoint of the target range at 41% including the impact of capital
spending on the Horizon Project.
Readers are cautioned that as the debt to book capitalization ratio has no
defined meaning under GAAP, this financial measure may not be comparable
to similar measures provided by other reporting entities. Further, there
can be no assurances that the Company will continue to use this measure to
monitor capital or will not alter the method of calculation of this
measure at some point in the future.
2008 | 2007
----------------------------------------------------------------------------------------------|-----------------
Long-term debt (1) $ 13,016 | $ 10,940
Total shareholders' equity $ 18,374 | $ 13,321
Debt to book capitalization 41% | 45%
==============================================================================================|=================
(1) Includes the current portion of long-term debt.
90 CANADIAN NATURAL
12. NET EARNINGS PER COMMON SHARE
(thousands of shares) 2008 | 2007 2006
--------------------------------------------------------------------------------------------|--------------------------------
Weighted average common shares outstanding - basic and diluted 540,647 | 539,336 537,339
Net earnings - basic and diluted $ 4,985 | $ 2,608 $ 2,524
Net earnings per common share - basic and diluted $ 9.22 | $ 4.84 $ 4.70
============================================================================================|================================
13. FINANCIAL INSTRUMENTS
The carrying values of the Company's financial instruments by category are
as follows:
2008
-----------------------------------------------------------------------------------------------------------------------------
Loans and Other
receivables financial
at Held for liabilities at
amortized trading at amortized
Asset (liability) cost fair value cost
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ - $ 27 $ -
Accounts receivable 1,059 - -
Risk management - 2,119 -
Accounts payable - - (383)
Accrued liabilities - - (1,802)
Other long-term liabilities - - (105)
Long-term debt (1) - - (13,016)
-----------------------------------------------------------------------------------------------------------------------------
$ 1,059 $ 2,146 $ (15,306)
=============================================================================================================================
(1) Includes the current portion of long-term debt.
2007
-----------------------------------------------------------------------------------------------------------------------------
Loans and Other
receivables financial
at Held for liabilities at
amortized trading at amortized
Asset (liability) cost fair value cost
-----------------------------------------------------------------------------------------------------------------------------
Cash and cash equivalents $ - $ 21 $ -
Accounts receivable 1,143 - -
Accounts payable - - (379)
Accrued liabilities - - (1,567)
Risk management - (1,474) -
Other long-term liabilities - - (86)
Long-term debt - - (10,940)
-----------------------------------------------------------------------------------------------------------------------------
$ 1,143 $ (1,453) $ (12,972)
=============================================================================================================================
The carrying value of the Company's financial instruments approximates
their fair value, except for fixed rate long-term debt as noted below:
2008 | 2007
-------------------------------------------------------------------------------------------|---------------------------------
Carrying value Fair value | Carrying value Fair value
-------------------------------------------------------------------------------------------|---------------------------------
Fixed rate long-term debt (1) $ 8,943 $ 7,649 | $ 6,244 $ 6,259
===========================================================================================|=================================
(1) The carrying value of US$350 million of 5.45% notes due October 2012,
and US$350 million of 4.90% notes due December 2014, have been
adjusted by $68 million (2007 - $9 million) to reflect the fair value
impact of hedge accounting.
CANADIAN NATURAL 91
Risk Management
The changes in estimated fair values of derivative financial instruments
included in the risk management asset (liability) were recognized in the
financial statements as follows:
2008 | 2007
---------------------------------------------------------------------------------|---------------------
Asset (liability) Risk | Risk
management | management
mark-to-market | mark-to-market
---------------------------------------------------------------------------------|---------------------
Balance - beginning of year $ (1,474)| $ 128
Retained earnings effect of adoption of financial |
instruments standards - | 14
Net cost of outstanding put options 297 | 58
Net change in fair value of outstanding derivative |
financial instruments attributable to: |
Risk management activities 3,090 | (1,400)
Interest expense 60 | 9
Foreign exchange 449 | (350)
Other comprehensive income 18 | 125
Settlement of interest rate swaps (20)| -
---------------------------------------------------------------------------------|---------------------
2,420 | (1,416)
Add: put premium financing obligations (1) (301)| (58)
---------------------------------------------------------------------------------|---------------------
Balance - end of year 2,119 | (1,474)
Less: current portion 1,851 | (1,227)
---------------------------------------------------------------------------------|---------------------
$ 268 | $ (247)
=================================================================================|=====================
(1) The Company has negotiated payment of put option premiums with
various counterparties at the time of actual settlement of the
respective options. These obligations have been reflected in the net
risk management asset (liability).
Net (gains) losses from risk management activities for the years ended
December 31 were as follows:
2008 | 2007 2006
------------------------------------------------------------------------|------------------------------------
Net realized risk management loss $ 1,860 | $ 162 $ 1,325
Net unrealized risk management (gain) loss (3,090)| 1,400 (1,013)
------------------------------------------------------------------------|------------------------------------
$ (1,230)| $ 1,562 $ 312
========================================================================|====================================
Financial risk Factors
a) Market risk
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
The Company's market risk is comprised of commodity price risk, interest
rate risk, and foreign currency exchange risk.
Commodity price risk management
The Company uses commodity derivative financial instruments to manage its
exposure to commodity price risk associated with the sale of its future
crude oil and natural gas production. At December 31, 2008, the Company
had the following net derivative financial instruments outstanding to
manage its commodity price exposures:
Remaining term Volume Weighted average price Index
-----------------------------------------------------------------------------------------------------------
Crude oil
Crude oil price collars Jan 2009 - Dec 2009 25,000 bbl/d US$70.00 - US$111.56 WTI
Apr 2009 - Jun 2009 4,000 bbl/d US$70.00 - US$90.00 WTI
-----------------------------------------------------------------------------------------------------------
Crude oil puts Jan 2009 - Dec 2009 92,000 bbl/d US$100.00 WTI
===========================================================================================================
The net cost of outstanding put options of US$242 million will be settled
in 2009.
Remaining term Volume Weighted average price Index
-----------------------------------------------------------------------------------------------------------
Natural gas
Natural gas price collars (1) Jan 2009 - Mar 2009 500,000 GJ/d C$6.00 - C$8.63 AECO
===========================================================================================================
(1) Subsequent to December 31, 2008, the Company entered into 220,000
GJ/d of C$6.00 - C$8.00 natural gas AECO collars for the period
January to December 2010.
The Company's outstanding commodity derivative financial instruments are
expected to be settled monthly based on the applicable index pricing for
the respective contract month.
There were no commodity derivative financial instruments designated as
hedges at December 31, 2008.
In addition to the derivative financial instruments noted above,
subsequent to December 31, 2008, the Company entered into natural gas
physical sales contracts for 400,000 GJ/d at an average fixed price of
C$5.29 per GJ at AECO for the period April to December 2009.
92 CANADIAN NATURAL
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed rate
long-term debt and to interest rate cash flow risk on its floating rate
long-term debt. The Company enters into interest rate swap contracts to
manage its fixed to floating interest rate mix on long-term debt. The
interest rate swap contracts require the periodic exchange of payments
without the exchange of the notional principal amounts on which the
payments are based. At December 31, 2008, the Company had the following
interest rate swap contracts outstanding:
Amount Fixed
Remaining term ($ millions) rate Floating Rate
-----------------------------------------------------------------------------------------------------------
Interest rate
Swaps - fixed to floating Jan 2009 - Dec 2014 US$350 4.90% LIBOR (1) + 0.38%
===========================================================================================================
(1) London Interbank Offered Rate.
All interest rate related derivative financial instruments designated as
hedges at December 31, 2008 were classified as fair value hedges.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in Canada
primarily related to its US dollar denominated long-term debt and working
capital. The Company is also exposed to foreign currency exchange rate
risk on transactions conducted in other currencies in its subsidiaries and
in the carrying value of its self-sustaining foreign subsidiaries. The
Company periodically enters into cross currency swap contracts and foreign
currency forward contracts to manage known currency exposure on US dollar
denominated long-term debt and working capital. The cross currency swap
contracts require the periodic exchange of payments with the exchange at
maturity of notional principal amounts on which the payments are based. At
December 31, 2008, the Company had the following cross currency swap
contracts outstanding:
Exchange Interest Interest
Amount rate rate rate
Remaining Term ($millions) (US$/C$) (US$) (C$)
-------------------------------------------------------------------------------------------------------------
Cross currency
Swaps Jan 2009 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2009 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2009 - Mar 2038 US$550 1.170 6.25% 5.76%
=============================================================================================================
All cross currency swap derivative financial instruments designated as
hedges at December 31, 2008 were classified as cash flow hedges.
In addition to the cross currency swap contracts noted above, the Company
periodically utilizes foreign currency forward contracts to manage certain
foreign currency cash management requirements. At December 31, 2008, the
Company had US$408 million of these contracts outstanding, with terms of
approximately 30 days or less.
Financial instrument sensitivities
As required by Canadian GAAP, effective January 1, 2008, the Company must
provide certain quantitative sensitivities related to its financial
instruments, which are prepared on a different basis than those
sensitivities currently disclosed in the Company's other continuous
disclosure documents. The following table summarizes the annualized
sensitivities of the Company's net earnings and other comprehensive income
to changes in the fair value of financial instruments outstanding as at
December 31, 2008, resulting from changes in the specified variable, with
all other variables held constant. These sensitivities are limited to the
impact of changes in a specified variable applied to financial instruments
only and do not represent the impact of a change in the variable on the
operating results of the Company taken as a whole. Further, these
sensitivities are theoretical, as changes in one variable may contribute
to changes in another variable, which may magnify or counteract the
sensitivities. In addition, changes in fair value generally can not be
extrapolated because the relationship of a change in an assumption to the
change in fair value may not be linear.
Impact on other
Impact on comprehensive
net earnings income
-------------------------------------------------------------------------------------------------------
Commodity price risk
Increase WTI US$1.00/bbl $ (32) $ -
Decrease WTI US$1.00/bbl $ 32 $ -
Increase AECO C$0.10/mcf $ (1) $ -
Decrease AECO C$0.10/mcf $ 1 $ -
Interest rate risk
Increase interest rate 1% $ (32) $ (27)
Decrease interest rate 1% $ 32 $ 33
Foreign currency exchange rate risk
Increase exchange rate by US$0.01 $ (35) $ -
Decrease exchange rate by US$0.01 $ 35 $ -
=======================================================================================================
CANADIAN NATURAL 93
b) Credit risk
Credit risk is the risk that a party to a financial instrument will cause
a financial loss to the Company by failing to discharge an obligation.
Counterparty credit risk management
The Company's 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 these risks by reviewing 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. At December 31, 2008, substantially all of
the Company's accounts receivables were due within normal trade terms.
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 entering into agreements
with counterparties that are substantially all investment grade financial
institutions and other entities. At December 31, 2008, the Company had net
risk management assets of $2,119 million (December 31, 2007 - $20 million)
with specific counterparties related to derivative financial instruments.
The Company believes that its counterparties currently have the financial
capacity to settle outstanding obligations in the normal course of
business.
c) Liquidity Risk
Liquidity risk is the risk that the Company will encounter difficulty in
meeting obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient
cash and cash equivalents, along with other sources of capital, consisting
primarily of cash flow from operating activities, available credit
facilities, and access to debt capital markets, to meet obligations as
they become due. Due to fluctuations in the timing of the receipt and/or
disbursement of operating cash flows, the Company believes it has adequate
bank credit facilities to provide liquidity.
The maturity dates for financial liabilities are as follows:
Less than 1 1 to less 2 to less
year than 2 years than 5 years Thereafter
------------------------------------------------------------------------------------------------------------------
Accounts payable $ 383 $ - $ - $ -
Accrued liabilities $ 1,802 $ - $ - $ -
Other long-term liabilities $ 86 $ 18 $ 1 $ -
Long-term debt (1) $ 2,385 $ 400 $ 1,809 $ 6,707
==================================================================================================================
(1) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or
transaction costs. No debt repayments are reflected for $1,725
million of revolving bank credit facilities due to the extendable
nature of the facilities.
14. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
2009 2010 2011 2012 2013 thereafter
-----------------------------------------------------------------------------------------------------------------
Product transportation
and pipeline $ 219 $ 184 $ 159 $ 133 $ 124 $ 1,175
Offshore equipment
operating leases $ 175 $ 145 $ 144 $ 116 $ 117 $ 398
Offshore drilling $ 251 $ 62 $ - $ - $ - $ -
Asset retirement
obligations (1) $ 6 $ 7 $ 6 $ 6 $ 6 $ 4,443
Office leases $ 25 $ 29 $ 23 $ 2 $ 2 $ 1
Other $ 321 $ 180 $ 17 $ 12 $ 8 $ 19
=================================================================================================================
(1) 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 2009 - 2013 represent the minimum required expenditures to
meet these obligations. Actual expenditures in any particular year
may exceed these minimum amounts.
The Company is defendant and plaintiff in a number of legal actions that
arise in the normal course of business. In addition, the Company is
subject to certain contractor construction claims related to the Horizon
Project. The Company believes that any liabilities that might arise
pertaining to any such matters would not have a material effect on its
consolidated financial position.
94 CANADIAN NATURAL
15. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Changes in non-cash working capital were as follows:
2008 2007 2006
------------------------------------------------------------------------------------------------------------
Decrease (increase) in non-cash working capital
Accounts receivable and other $ 111 $ 334 $ (116)
Accounts payable (4) (456) 157
Accrued liabilities (15) (402) (582)
------------------------------------------------------------------------------------------------------------
Net change in non-cash working capital $ 92 $ (524) $ (541)
------------------------------------------------------------------------------------------------------------
Relating to:
Operating activities $ (189) $ (346) $ (679)
Financing activities 46 8 37
Investing activities 235 (186) 101
------------------------------------------------------------------------------------------------------------
$ 92 $ (524) $ (541)
============================================================================================================
Other cash flow information: 2008 2007 2006
------------------------------------------------------------------------------------------------------------
Interest paid $ 574 $ 556 $ 262
Taxes paid $ 558 $ 418 $ 703
============================================================================================================
16. BUSINESS COMBINATIONS
Anadarko Canada Corporation
In November 2006, the Company completed the acquisition of all of the
issued and outstanding common shares 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 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 allocation of the net purchase price to
assets acquired and liabilities assumed based on their fair values was as
follows:
November 2, 2006
-------------------------------------------------------------------------------------------------------------
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 forward contracts designated as hedges of the
ACC purchase price.
CANADIAN NATURAL 95
17. SEGMENTED INFORMATION
The Company's conventional crude oil and natural gas activities are
conducted in three geographic segments: North America, North Sea and
Offshore West Africa. These activities include the exploration,
development, production and marketing of conventional crude oil, natural
gas liquids and natural gas.
The Company's Horizon Project is a separate segment from conventional
crude oil and natural gas activities as the bitumen will be recovered
through mining operations. 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 reported in the segmented information as other.
Inter-segment eliminations include internal transportation, electricity
charges and natural gas sales.
Conventional Crude Oil and Natural Gas
------------------------------------------------------------------------------------------------------------
North America North Sea Offshore West Africa
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
2008 | 2007 2006 2008 | 2007 2006 2008 | 2007 2006
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Segmented revenue $ 13,496 | $ 10,149 $ 9,066 $ 1,769 | $ 1,597 $ 1,616 $ 944 | $ 776 $ 950
Less: royalties (1,876)| (1,318) (1,203) (4)| (3) (3) (143)| (70) (39)
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Revenue, net of | | |
royalties 11,620 | 8,831 7,863 1,765 | 1,594 1,613 801 | 706 911
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Segmented | | |
expenses | | |
Production 1,881 | 1,642 1,436 457 | 432 390 102 | 94 106
Transportation | | |
and blending 1,975 | 1,595 1,465 10 | 16 15 1 | 1 1
Depletion, | | |
depreciation | | |
and | | |
amortization 2,236 | 2,350 1,897 317 | 340 297 132 | 165 189
Asset retirement | | |
obligation | | |
accretion 42 | 38 35 27 | 30 31 2 | 2 2
Realized risk | | |
management | | |
activities 1,861 | 129 1,022 (1) | 33 303 - | - -
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Total segmented | | |
expenses 7,995 | 5,754 5,855 810 | 851 1,036 237 | 262 298
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Segmented | | |
earnings | | |
before the | | |
following $ 3,625 | $ 3,077 $ 2,008 $ 955 | $ 743 $ 577 $ 564 | $ 444 $ 613
-------------------------------------|-----------------------------------|-----------------------------------|----------------------
Non-segmented expenses
Administration
Stock-based compensation (recovery) expense
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 expense
Future income tax expense (recovery)
------------------------------------------------------------------------------------------------------------------------------------
Net earnings
====================================================================================================================================
Capital Expenditures
2008 | 2007
------------------------------------------------|----------------------------------------------
Non cash | Non cash
and fair | and fair
Net value Capitalized | Net value Capitalized
expenditure changes (1) costs | expenditure changes (1) costs
---------------------------------------------------------------------------------|----------------------------------------------
Conventional crude oil and natural gas |
North America $ 2,344 $ (7) $ 2,337 | $ 2,428 $ 52 $ 2,480
North Sea 319 (127) 192 | 439 (77) 362
Offshore West 811 6 817 | 159 (11) 148
Africa |
Other 1 - 1 | 1 - 1
---------------------------------------------------------------------------------|----------------------------------------------
3,475 (128) 3,347 | 3,027 (36) 2,991
Horizon Project (2) 3,912 10 3,922 | 3,301 - 3,301
Midstream 9 - 9 | 6 - 6
Head office 17 - 17 | 20 - 20
---------------------------------------------------------------------------------|----------------------------------------------
$ 7,413 $ (118) $ 7,295 | $ 6,354 $ (36) $ 6,318
=================================================================================|==============================================
(1) Asset retirement obligations, future income tax adjustments related
to differences between carrying value and tax value, and other fair
value adjustments.
(2) Net expenditures for the Horizon Project also include capitalized
interest, stock-based compensation, and the impact of intersegment
eliminations.
96 CANADIAN NATURAL
Inter-segment
elimination
Midstream and other Total
--------------------------------|--------------------------------|-----------------------------------|--------------------------
2008 | 2007 2006 2008 | 2007 2006 2008 | 2007 2006
--------------------------------|--------------------------------|-----------------------------------|--------------------------
$ 77 | $ 74 $ 72 $ (113)| $ (53) $ (61 $ 16,173 | $ 12,543 $ 11,643
- | - - 6 | - - (2,017)| (1,391) (1,245)
--------------------------------|--------------------------------|-----------------------------------|--------------------------
77 | 74 72 (107)| (53) (61) 14,156 | 11,152 10,398
--------------------------------|--------------------------------|-----------------------------------|--------------------------
25 | 22 23 (14)| (6) (6) 2,451 | 2,184 1,949
- | - - (50)| (42) (38) 1,936 | 1,570 1,443
8 | 8 8 (10)| - - 2,683 | 2,863 2,391
- | - - - | - - 71 | 70 68
- | - - - | - - 1,860 | 162 1,325
--------------------------------|--------------------------------|-----------------------------------|--------------------------
33 | 30 31 (74)| (48) (44) 9,001 | 6,849 7,176
--------------------------------|--------------------------------|-----------------------------------|--------------------------
| | |
$ 44 | $ 44 $ 41 $ (33)| $ (5) $ (17) 5,155 | 4,303 3,222
--------------------------------|--------------------------------|-----------------------------------|--------------------------
180 | 208 180
(52)| 193 139
128 | 276 140
(3,090)| 1,400 (1,013)
718 | (471) 122
--------------------------------|--------------------------------|-----------------------------------|--------------------------
(2,116)| 1,606 (432)
--------------------------------|--------------------------------|-----------------------------------|--------------------------
7,271 | 2,697 3,654
178 | 165 256
501 | 380 222
1,607 | (456) 652
--------------------------------|--------------------------------|-----------------------------------|--------------------------
$ 4,985 | $ 2,608 $ 2,524
-----------------------------------------------------------------------------------------------------|--------------------------
Segmented Assets
2008 | 2007
-----------------------------------------------------------------------------------------------------|---------------
Conventional crude oil and natural gas
North America $ 24,875 | $ 23,617
North Sea 2,638 | 1,957
Offshore West Africa 2,013 | 1,354
Other 64 | 41
Horizon Project 12,677 | 8,740
Midstream 315 | 333
Head office 68 | 72
-----------------------------------------------------------------------------------------------------|---------------
$ 42,650 | $ 36,114
=====================================================================================================|===============
CANADIAN NATURAL 97
18. 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 (loss) as reported:
(millions of Canadian dollars, except per common
share amounts) Notes 2008 | 2007 2006
-----------------------------------------------------------------------------------------|----------------------------
Net earnings - Canadian GAAP $ 4,985 | $ 2,608 $ 2,524
Adjustments |
Depletion, net of taxes of $2,503 million |
(2007 - $1 million, 2006 - $1 million) (A,D) (6,169)| (10) 2
Stock-based compensation, net of taxes of $32 |
million (2007 - $3 million, 2006 - $18 million) (B) (76)| (22) (40)
Future income taxes (G) 234 | (234) -
Derivative financial instruments and hedging |
activities, net of taxes of $nil (2007 - $nil, |
2006 - $15 million) (C,D) - | - 117
-----------------------------------------------------------------------------------------|----------------------------
Net earnings (loss) before cumulative effect (1,026)| 2,342 2,603
of change in accounting policy - US GAAP |
Cumulative effect of change in accounting policy, |
net of taxes of $nil (2007 - $nil, 2006 - $3 |
million) (B) - | - (8)
-----------------------------------------------------------------------------------------|----------------------------
Net earnings (loss) - US GAAP $ (1,026)| $ 2,342 $ 2,595
-----------------------------------------------------------------------------------------|----------------------------
Net earnings (loss) before cumulative effect of change |
in accounting policy - US GAAP per common share |
Basic $ (1.90)| $ 4.34 $ 4.84
Diluted (F) $ (1.90)| $ 4.32 $ 4.77
-----------------------------------------------------------------------------------------|----------------------------
Net earnings (loss) - US GAAP per common share |
Basic $ (1.90)| $ 4.34 $ 4.83
Diluted (F) $ (1.90)| $ 4.32 $ 4.75
=========================================================================================|============================
Comprehensive income (loss) under US GAAP would be as follows:
(millions of Canadian dollars) Notes 2008 | 2007 2006
------------------------------------------------------------------------------------------|---------------------------
Comprehensive income - Canadian GAAP $ 5,175 | $ 2,534 $ 2,520
US GAAP earnings adjustments (6,011) | (266) 71
Derivative financial instruments and hedging |
activities, net of taxes of $nil (2007 - $nil |
million; 2006 - $394 million) (C) - | - 805
------------------------------------------------------------------------------------------|---------------------------
Comprehensive income (loss) - US GAAP $ (836) | $ 2,268 $ 3,396
==========================================================================================|===========================
The application of US GAAP would have the following effects on the
consolidated balance sheets as reported:
2008
----------------------------------------------------------------------------------------------------------------------
Notes Canadian Increase US
GAAP (Decrease) GAAP
----------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars)
Current assets $ 3,392 $ - $ 3,392
Property, plant and equipment (A,B,D,E) 38,966 (8,551) 30,415
Other long-term assets (H) 292 55 347
----------------------------------------------------------------------------------------------------------------------
$ 42,650 $ (8,496) $ 34,154
----------------------------------------------------------------------------------------------------------------------
Current liabilities (B) $ 3,420 $ 150 $ 3,570
Long-term debt (H) 12,596 55 12,651
Other long-term liabilities (B) 1,124 15 1,139
Future income tax (A,B,D,E,G) 7,136 (2,474) 4,662
Share capital 2,768 - 2,768
Retained earnings 15,344 (6,242) 9,102
Accumulated other comprehensive income 262 - 262
----------------------------------------------------------------------------------------------------------------------
$ 42,650 $ (8,496) $ 34,154
======================================================================================================================
98 CANADIAN NATURAL
2007
---------------------------------------------------------------------------------------------------------------------
Canadian Increase US
(millions of Canadian dollars) Notes GAAP (Decrease) GAAP
---------------------------------------------------------------------------------------------------------------------
Current assets $ 2,181 $ - $ 2,181
Property, plant and equipment (A,B,D,E) 33,902 91 33,993
Other long-term assets (H) 31 51 82
---------------------------------------------------------------------------------------------------------------------
$ 36,114 $ 142 $ 36,256
---------------------------------------------------------------------------------------------------------------------
Current liabilities (B) $ 3,563 $ 66 $ 3,629
Long-term debt (H) 10,940 51 10,991
Other long-term liabilities (B) 1,561 20 1,581
Future income tax (A,B,D,E,G) 6,729 236 6,965
Share capital 2,674 - 2,674
Retained earnings 10,575 (231) 10,344
Accumulated other comprehensive income 72 - 72
---------------------------------------------------------------------------------------------------------------------
$ 36,114 $ 142 $ 36,256
=====================================================================================================================
Notes:
(A) Under Canadian full cost accounting rules, costs capitalized in each
country 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") as described in note 1(H). 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
current and prior years resulted in the recognition of ceiling test
impairments under US GAAP, which reduced property, plant and
equipment by $8,697 million in 2008 (2007 - $36 million, 2006 - $40
million).
For the year ended December 31, 2008, US GAAP net earnings would have
decreased by $6,164 million, net of income taxes of $2,501 million to
reflect the impact of a current year ceiling test impairment. In
addition, the impact of prior ceiling test impairments would have
increased US GAAP net earnings by $3 million (2007 - decreased by $4
million, 2006 - increased by $3 million), net of income taxes of $1
million (2007 - $8 million, 2006 - $2 million) to reflect the impact
of lower depletion charges. The 2007 income tax effect includes the
effect of enacted Canadian income tax rate changes on this item.
(B) The Company accounts for its stock-based compensation liability under
Canadian GAAP using the intrinsic value method, as described in note
1(P). 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, 2008, US GAAP net
earnings would have decreased by $76 million (2007 - $22 million,
2006 - $48 million), net of income taxes of $32 million (2007 - $3
million, 2006 - $21 million including the cumulative effect of the
change in accounting policy of $8 million, net of income taxes of $3
million). The 2007 income tax effect includes the effect of enacted
Canadian income tax rate changes on this item.
(C) Effective January 1, 2007, the Company adopted new accounting
standards for financial instruments. The Company's accounting
policies for financial instruments under Canadian GAAP are described
in notes 1(Q) and 1(R). After adopting the new standards, Canadian
GAAP is substantially harmonized with US GAAP as prescribed by FAS
133, "Accounting for Derivative Financial Instruments and Hedging
Activities," as amended by FAS 138 and FAS 149.
Prior to adoption of the new accounting policies, the net earnings
associated with realized and unrealized hedge ineffectiveness on
derivative contracts designated as cash flow hedges during the year
ended December 31, 2006 would have been $29 million, net of income
taxes of $15 million. Comprehensive income would have increased by
$805 million as a result of recording all derivative financial
instruments at fair value in accordance with US GAAP.
(D) During 2006, 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, for
the year ended December 31, 2006, the $88 million after-tax gain on
the derivative financial instruments would have been included in net
earnings. For the year ended December 31, 2008, US GAAP net earnings
would have been decreased by $8 million (2007 - $6 million, 2006 - $1
million), net of income taxes of $3 million (2007 - $7 million, 2006
- $1 million), to reflect the impact of higher depletion charges. The
2007 income tax effect includes the effect of enacted Canadian income
tax rate changes on this item.
CANADIAN NATURAL 99
(E) 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. As a result of applying
US GAAP, an additional $27 million would have been capitalized to
property, plant and equipment in 2004.
(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 as 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, 2008, no
additional shares would have been included in the calculation of
diluted earnings per share for US GAAP as the impact would have been
anti-dilutive (2007 - 3,376,000 additional shares, 2006 - 8,762,000
additional shares).
(G) Under Canadian GAAP, the effects of income tax changes are recognized
when the changes are considered substantively enacted. Under US GAAP,
the income tax changes would not be recognized until the changes are
enacted into law. For the year ended December 31, 2007, the
differences between substantively enacted and enacted tax legislation
resulted in a difference in timing of the recognition of a $234
million future income tax recovery.
(H) Effective January 1, 2007, under Canadian GAAP, debt issue costs on
long-term debt must be included in the carrying value of the related
debt. Under US GAAP, these items must be recorded as a deferred
charge. Application of US GAAP would have resulted in the balance
sheet reclassification of $55 million of debt issue costs from
long-term debt to deferred charges in 2008 (2007 - $51 million).
There was no difference from Canadian GAAP prior to 2007.
(I) In September 2006, the FASB issued FAS 157 "Fair Value Measurements"
effective for fiscal years beginning after November 15, 2007. The
implementation date was subsequently delayed until years beginning on
or after November 15, 2008 except for non financial assets and non
financial liabilities that are recognized or disclosed at fair value
in the financial statements on a recurring basis (at least annually).
FAS 157 standardizes the meaning of "Fair Value" in all FASB
statements that refer to fair value and expands disclosures about
fair value measurements. The adoption of this standard did not result
in a Canadian and US GAAP reconciling item.
(J) In February 2007, the FASB issued FAS 159 "The Fair Value Option for
Financial Assets and Financial Liabilities" effective for fiscal
years beginning after November 15, 2007. FAS 159 allows entities to
carry most financial instruments at fair value, even if existing
standards would not require this. The adoption of this standard did
not result in a US GAAP reconciling item.
(K) In December 2007, the FASB issued FAS 141(R) "Business Combinations",
which replaces FAS 141 effective for fiscal years beginning after
December 15, 2008. FAS 141(R) retains the purchase method of
accounting and requires assets acquired and liabilities assumed in a
business combination to be measured at fair value at the date of
acquisition. The standard also requires acquisition-related costs and
restructuring costs to be recognized separately from the business
combination. This standard is to be applied prospectively to all
business combinations subsequent to the effective date and does not
require restatement of previously completed business combinations.
(L) US GAAP - Recently issued accounting standards
During 2008, the US Securities and Exchange Commission adopted
revisions to its oil and gas reporting disclosures contained in
regulation S-K and regulation S-X. These revisions change the price
basis for calculating oil and gas reserves from a single-day,
year-end price to a monthly average price based on "first day of the
month" price. These revisions will impact the reserves used in the
Company's accounting for depletion and its calculation of the ceiling
test under US GAAP. These revisions are effective for filings made on
or after January 1, 2010, and will be applied prospectively with no
retroactive restatement.
100 CANADIAN NATURAL
ADDITIONAL DISCLOSURE
DISCLOSURE CONTROLS AND PROCEDURES
----------------------------------
As of the end of the registrant's fiscal year ended December 31, 2008, 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 principal 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 ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING
--------------------------------------------------------------------
The required disclosure is included in the "Management's Assessment of Internal
Control Over Financial Reporting" that accompanies Canadian Natural's audited
consolidated financial statements for the fiscal year ended December 31, 2008,
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
Canadian Natural's audited consolidated financial statements for the fiscal year
ended December 31, 2008, filed as part of this Annual Report on Form 40-F.
CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
----------------------------------------------------
During the fiscal year ended December 31, 2008, there were no changes in
Canadian Natural's internal control over financial reporting that have
materially affected, or are reasonably likely to materially affect, Canadian
Natural's internal control 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 and is designed to ensure that Canadian
Natural's business is consistently conducted in a 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.
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, 2008 and December 31, 2007, 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 $2,685,800 for 2008 and were $2,729,315 for 2007.
AUDIT-RELATED FEES
The aggregate fees billed for each of the last two fiscal years of Canadian
Natural, ending December 31, 2008 and December 31, 2007, for audit-related
services by PwC including debt covenant compliance and Crown Royalty Statements,
were $156,300 for 2008 and were $164,000 for 2007. 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, 2008 and December 31, 2007, for professional
services rendered by PwC for tax-related services related to expatriate personal
tax compliance as well as other corporate tax return matters provided in 2008
were $91,500 for 2008 and were $154,459 for 2007. 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, 2008 and December 31, 2007 for other services were
$9,500 for 2008 and were $9,440 for 2007. The fees for other services paid in
2008 related to accessing resource materials through PwC's accounting literature
library. Canadian Natural's Audit Committee approved all of the noted services.
AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES
----------------------------------------------------
The Audit Committee's duties and responsibilities include the review and
approval of fees to be paid to the independent auditors, scope and timing of the
audit and other related services rendered by the independent auditors. The Audit
Committee also reviews and approves the independent auditor's annual audit plan,
including scope, staffing, locations and reliance upon management and internal
audit department prior to the commencement of the audit and reviews and approves
proposed non-audit services to be provided by the independent auditors, except
those non-audit services prohibited by legislation. Canadian Natural did not
rely on the de minimis exemption provided by paragraph (c)(7)(i)(c) of Rule 2.01
of Regulation S-X in 2008.
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 60 of Canadian Natural's Management's Discussion
and Analysis of Financial Condition and Results of Operations for the fiscal
year ended December 31, 2008, filed herewith, under the caption "Commitments and
Off Balance Sheet Arrangements".
CONTRACTUAL OBLIGATIONS
-----------------------
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. These
commitments primarily relate to firm commitments for gathering, processing and
transmission services; operating leases relating to offshore FPSOs, drilling
rigs and office space; expenditures relating to ARO; as well as long-term debt
and interest payments. As at December 31, 2008, no entities were consolidated
under CICA Handbook Accounting Guideline 15, "Consolidation of Variable Interest
Entities". The following table summarizes the Company's commitments as at
December 31, 2008:
($ millions) 2009 2010 2011 2012 2013 Thereafter
-----------------------------------------------------------------------------------------------
Product transportation and pipeline $ 219 $ 184 $ 159 $ 133 $ 124 $ 1,175
Offshore equipment operating lease $ 175 $ 145 $ 144 $ 116 $ 117 $ 398
Offshore drilling $ 251 $ 62 $ - $ - $ - $ -
Asset retirement obligations (1) $ 6 $ 7 $ 6 $ 6 $ 6 $ 4,443
Long-term debt (2) $ 2,385 $ 400 $ 490 $ 429 $ 890 $ 6,707
Interest expense (3) $ 610 $ 565 $ 543 $ 490 $ 428 $ 5,992
Office lease $ 25 $ 29 $ 23 $ 2 $ 2 $ 1
Other $ 321 $ 180 $ 17 $ 12 $ 8 $ 19
===============================================================================================
(1) Amounts represent management's estimate of the future undiscounted payments
to settle ARO related to resource properties, facilities, and production
platforms, based on current legislation and industry operating practices.
Amounts disclosed for the period 2009 - 2013 represent the minimum required
expenditures to meet these obligations. Actual expenditures in any
particular year may exceed these minimum amounts.
(2) The long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or transaction
costs. No debt repayments are reflected for $1,725 million of revolving
bank credit facilities due to the extendable nature of the facilities.
(3) Interest expense amounts represent the scheduled fixed rate and variable
rate cash payments related to long-term debt. Interest on variable rate
long-term debt was estimated based upon prevailing interest rates as of
December 31, 2008.
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, 2008, which forms part of this Form 40-F. The Annual
Information Form is also available through the System for Electronic Document
and Analysis and Retrieval (SEDAR) at www.sedar.com.
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
UNDERTAKING
Canadian Natural undertakes to make available, in person or by telephone,
representatives to respond to inquiries made by the Commission staff, and to
furnish promptly, when requested to do so by the Commission staff, information
relating to: the securities registered pursuant to Form 40-F; the securities in
relation to which the obligation to file an annual report on Form 40-F arises;
or transactions in said securities.
CONSENT TO SERVICE OF PROCESS
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.
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 25th day of March, 2009.
CANADIAN NATURAL RESOURCES LIMITED
By: SIGNED "STEVE W. LAUT"
----------------------
Name: Steve W. Laut
Title: President and Chief Operating Officer
Documents filed as part of this report:
EXHIBIT INDEX
Exhibit No. Description
----------- -----------
1. Supplementary Oil & Gas Information for the fiscal year ended
December 31, 2008.
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 GLJ Petroleum Consultants Ltd., independent petroleum
engineering consultants.
EXHIBIT 1
SUPPLEMENTARY OIL & GAS INFORMATION FOR
THE FISCAL YEAR ENDED DECEMBER 31, 2008
SUPPLEMENTARY OIL & GAS INFORMATION (unaudited)
This supplementary crude oil and natural gas information is provided in
accordance with the United States Financial Accounting Standards Board Statement
69 ("FAS 69"), "Disclosures about Oil and Gas Producing Activities", and where
applicable is reconciled to the financial information prepared in accordance
with generally accepted accounting principles in the United States ("US GAAP").
NET PROVED CRUDE OIL AND NATURAL GAS RESERVES
The Company retains qualified independent reserves evaluators to evaluate the
Company's proved crude oil and natural gas reserves.
o For the year ended December 31, 2008, the reports by Sproule Associates
Limited ("Sproule") covered 100% of the Company's conventional reserves.
o For the years ended December 31, 2007, 2006, and 2005 the reports by
Sproule and Ryder Scott Company covered 100% of the Company's conventional
reserves.
Proved crude oil and natural gas reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids ("NGLs") that geological and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Estimates of crude oil and natural gas reserves are subject to uncertainty and
will change as additional information regarding producing fields and technology
becomes available and as future economic and operating conditions change.
The following table summarizes the Company's proved and proved developed
conventional crude oil and natural gas reserves, net of royalties, as at
December 31, 2008, 2007, 2006, and 2005:
-------------------------------------------------------------------------------------------------------------------------------
North North Offshore
Crude oil and NGLs (mmbbl) America Sea West Africa Total
-------------------------------------------------------------------------------------------------------------------------------
Net proved reserves Reserves, December 31, 2005 694 290 134 1,118
Extensions and discoveries 53 3 - 56
Improved recovery 190 26 - 216
Purchases of reserves in place 26 - - 26
Sales of reserves in place - - - -
Production (75) (22) (13) (110)
Revisions of prior estimates (1) (1) 2 9 10
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2006 887 299 130 1,316
Extensions and discoveries 30 - - 30
Improved recovery 13 6 - 19
Purchases of reserves in place 1 - - 1
Sales of reserves in place - (3) - (3)
Production (77) (20) (10) (107)
Revisions of prior estimates (1) 66 28 8 102
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2007 920 310 128 1,358
Extensions and discoveries 51 - - 51
Improved recovery 17 6 4 27
Purchases of reserves in place - - - -
Sales of reserves in place - - - -
Production (76) (17) (8) (101)
Economic revisions due to prices 28 (81) 8 (45)
Revisions of prior estimates 8 38 10 56
-------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2008 948 256 142 1,346
===============================================================================================================================
Net proved developed reserves
December 31, 2005 402 214 80 696
December 31, 2006 420 214 63 697
December 31, 2007 426 240 70 736
December 31, 2008 428 97 107 632
===============================================================================================================================
(1) Revisions of prior estimates for the years ended December 31, 2007 and 2006
include the impact of economic revisions due to prices.
---------------------------------------------------------------------------------------------------------------------------------
North North Offshore
Natural gas (bcf) America Sea West Africa Total
---------------------------------------------------------------------------------------------------------------------------------
Net proved reserves
Reserves, December 31, 2005 2,741 29 72 2,842
Extensions and discoveries 250 - - 250
Improved recovery 74 - - 74
Purchases of reserves in place 1,111 - - 1,111
Sales of reserves in place (1) - - (1)
Production (433) (5) (3) (441)
Revisions of prior estimates (1) (37) 13 (13) (37)
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2006 3,705 37 56 3,798
Extensions and discoveries 134 - - 134
Improved recovery 132 3 - 135
Purchases of reserves in place 12 - - 12
Sales of reserves in place - - - -
Production (503) (5) (4) (512)
Revisions of prior estimates (1) 41 46 12 99
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2007 3,521 81 64 3,666
Extensions and discoveries 140 - - 140
Improved recovery 52 (1) 6 57
Purchases of reserves in place 77 - - 77
Sales of reserves in place (1) - - (1)
Production (449) (4) (4) (457)
Economic revisions due to prices (19) (56) 6 (69)
Revisions of prior estimates 202 47 22 271
---------------------------------------------------------------------------------------------------------------------------------
Reserves, December 31, 2008 3,523 67 94 3,684
=================================================================================================================================
Net proved developed reserves
December 31, 2005 2,300 16 10 2,326
December 31, 2006 2,934 17 12 2,963
December 31, 2007 2,731 58 53 2,842
December 31, 2008 2,690 45 89 2,824
=================================================================================================================================
(1) Revisions of prior estimates for the years ended December 31, 2007 and 2006
include the impact of economic revisions due to prices.
CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES
2008
-----------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Other Total
-----------------------------------------------------------------------------------------------------------------------------------
Proved properties $ 34,386 $ 4,155 $ 2,076 $ 14 $ 40,631
Unproved properties 2,271 12 595 26 2,904
-----------------------------------------------------------------------------------------------------------------------------------
36,657 4,167 2,671 40 43,535
Less: accumulated depletion
and depreciation (21,857) (3,366) (777) (14) (26,014)
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 14,800 $ 801 $ 1,894 $ 26 $ 17,521
===================================================================================================================================
2007
-----------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Other Total
-----------------------------------------------------------------------------------------------------------------------------------
Proved properties $ 32,061 $ 3,164 $ 1,695 $ 14 $ 36,934
Unproved properties 2,259 10 138 25 2,432
-----------------------------------------------------------------------------------------------------------------------------------
34,320 3,174 1,833 39 39,366
Less: accumulated depletion
and depreciation (12,213) (1,446) (645) (14) (14,318)
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 22,107 $ 1,728 $ 1,188 $ 25 $ 25,048
===================================================================================================================================
2006
-----------------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars) North North Offshore Total
America Sea West Africa Other
-----------------------------------------------------------------------------------------------------------------------------------
Proved properties $ 29,596 $ 3,346 $ 1,601 $ 14 $ 34,557
Unproved properties 2,244 24 84 24 2,376
-----------------------------------------------------------------------------------------------------------------------------------
31,840 3,370 1,685 38 36,933
Less: accumulated depletion (9,878) (1,341) (481) (14) (11,714)
and depreciation
-----------------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 21,962 $ 2,029 $ 1,204 $ 24 $ 25,219
===================================================================================================================================
COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES
2008
---------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Other Total
---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions
Proved $ 299 $ (7) $ 44 $ - $ 336
Unproved 84 1 1 - 86
Exploration 144 3 - 1 148
Development 1,810 195 772 - 2,777
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred $ 2,337 $ 192 $ 817 $ 1 $ 3,347
=================================================================================================================================
2007
---------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Other Total
---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions
Proved $ 55 $ (38) $ - $ - $ 17
Unproved 13 1 - - 14
Exploration 239 19 - 1 259
Development 2,173 380 148 - 2,701
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred $ 2,480 $ 362 $ 148 $ 1 $ 2,991
=================================================================================================================================
2006
---------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Other Total
---------------------------------------------------------------------------------------------------------------------------------
Property acquisitions
Proved $ 5,627 $ - $ 1 $ - $ 5,628
Unproved 910 - - - 910
Exploration 238 4 1 11 254
Development 2,807 628 133 - 3,568
---------------------------------------------------------------------------------------------------------------------------------
Costs incurred $ 9,582 $ 632 $ 135 $ 11 $ 10,360
=================================================================================================================================
RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES
The Company's results of operations from crude oil and natural gas producing
activities for the years ended December 31, 2008, 2007, and 2006 are summarized
in the following tables:
2008
--------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Total
--------------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas revenue, net of $ 8,126 $ 1,731 $ 801 $ 10,658
royalties and blending costs
Production (1,881) (457) (102) (2,440)
Transportation (327) (10) (1) (338)
Depletion, depreciation and amortization (1) (9,661) (1,564) (132) (11,357)
Asset retirement obligation accretion (42) (27) (2) (71)
Petroleum revenue tax - (143) - (143)
Income tax 1,128 235 (141) 1,222
--------------------------------------------------------------------------------------------------------------------------------
Results of operations $ (2,657) $ (235) $ 423 $ (2,469)
================================================================================================================================
(1) Includes the impact of a ceiling test impairt December 31, 2008 of $8,665
million, pre-tax.
2007
-----------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Total
-----------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas revenue, net of $ 7,441 $ 1,522 $ 709 $ 9,672
royalties and blending costs
Production (1,642) (432) (94) (2,168)
Transportation (335) (16) (1) (352)
Depletion, depreciation and amortization (2,359) (340) (165) (2,864)
Asset retirement obligation accretion (38) (30) (2) (70)
Petroleum revenue tax - (141) - (141)
Income tax (997) (282) (121) (1,400)
-----------------------------------------------------------------------------------------------------------------------------
Results of operations $ 2,070 $ 281 $ 326 $ 2,677
=============================================================================================================================
2006
-----------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars) North North Offshore Total
America Sea West Africa
-----------------------------------------------------------------------------------------------------------------------------
Crude oil and natural gas revenue, net of $ 5,707 $ 1,310 $ 911 $ 7,928
royalties and blending costs
Production (1,436) (390) (106) (1,932)
Transportation (326) (15) (1) (342)
Depletion, depreciation and amortization (1,894) (297) (189) (2,380)
Asset retirement obligation accretion (35) (31) (2) (68)
Petroleum revenue tax - (234) - (234)
Income tax (706) (172) (172) (1,050)
-----------------------------------------------------------------------------------------------------------------------------
Results of operations $ 1,310 $ 171 $ 441 $ 1,922
=============================================================================================================================
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL
AND NATURAL GAS RESERVES AND CHANGES THEREIN
The following standardized measure of discounted future net cash flows from
proved crude oil and natural gas reserves has been computed using year-end
sales prices and costs and year-end statutory income tax rates. A discount
factor of 10% has been applied in determining the standardized measure of
discounted future net cash flows. The Company does not believe that the
standardized measure of discounted future net cash flows will be representative
of actual future net cash flows and should not be considered to represent the
fair value of the crude oil and natural gas properties. Actual net cash flows
will differ from the presented estimated future net cash flows due to several
factors including:
o Future production will include production not only from proved properties,
but may also include production from probable and possible reserves;
o Future production of crude oil and natural gas from proved properties will
differ from reserves estimated;
o Future production rates will vary from those estimated;
o Future rather than year-end sales prices and costs will apply;
o Economic factors such as interest rates, income tax rates, regulatory and
fiscal environments and operating conditions will change;
o Future estimated income taxes do not take into account the effects of
future exploration expenditures; and
o Future development and asset retirement obligations will differ from those
estimated.
Future net revenues, development, production and restoration costs have been
based upon the estimates referred to above. The following tables summarize the
Company's future net cash flows relating to proved crude oil and natural gas
reserves based on the standardized measure as prescribed in FAS 69:
-------------------------------------------------------------------------------------------------------------------------------
2008
-------------------------------------------------------------------------------------------------------------------------------
(millions of Canadian dollars) North North Offshore Total
America Sea West Africa
-------------------------------------------------------------------------------------------------------------------------------
Future cash inflows $ 51,913 $ 13,681 $ 6,789 $ 72,383
Future production costs (23,747) (6,845) (3,000) (33,592)
Future development and asset retirement
obligations (9,238) (4,674) (364) (14,276)
Future income taxes (3,097) (2,011) (1,061) (6,169)
-------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 15,831 151 2,364 18,346
10% annual discount for timing of future
cash flows (6,872) (76) (1,011) (7,959)
-------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows $ 8,959 $ 75 $ 1,353 $ 10,387
===============================================================================================================================
2007
----------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Total
----------------------------------------------------------------------------------------------------------------------------------
Future cash inflows $ 71,069 $ 30,269 $ 9,921 $ 111,259
Future production costs (23,729) (9,316) (2,419) (35,464)
Future development and asset retirement
obligations (7,938) (4,021) (621) (12,580)
Future income taxes (9,508) (11,376) (1,978) (22,862)
----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 29,894 5,556 4,903 40,353
10% annual discount for timing of future
cash flows (13,952) (2,176) (2,505) (18,633)
----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows $ 15,942 $ 3,380 $ 2,398 $ 21,720
==================================================================================================================================
2006
----------------------------------------------------------------------------------------------------------------------------------
North North Offshore
(millions of Canadian dollars) America Sea West Africa Total
----------------------------------------------------------------------------------------------------------------------------------
Future cash inflows $ 63,368 $ 20,815 $ 7,779 $ 91,962
Future production costs (21,634) (8,077) (2,517) (32,228)
Future development and asset retirement
obligations (7,029) (4,348) (824) (12,201)
Future income taxes (9,118) (5,623) (1,372) (16,113)
----------------------------------------------------------------------------------------------------------------------------------
Future net cash flows 25,587 2,767 3,066 31,420
10% annual discount for timing of future
cash flows (11,214) (956) (1,258) (13,428)
----------------------------------------------------------------------------------------------------------------------------------
Standardized measure of future net cash flows $ 14,373 $ 1,811 $ 1,808 $ 17,992
==================================================================================================================================
The principal sources of change in the standardized measure of discounted future
net cash flows are summarized in the following table:
(millions of Canadian dollars) 2008 2007 2006
---------------------------------------------------------------------------------------------------------------------------
Sales of crude oil and natural gas produced, net of $ (9,679) $ (7,150) $ (5,635)
production costs
Net changes in sales prices and production costs (14,680) 7,412 (2,420)
Extensions, discoveries and improved recovery 820 1,429 4,769
Changes in estimated future development costs (715) (169) (1,885)
Purchases of proved reserves in place 113 39 2,406
Sales of proved reserves in place (1) (103) (2)
Revisions of previous reserve estimates 112 2,380 81
Accretion of discount 3,468 2,760 3,112
Changes in production timing and other 767 508 (2,156)
Net change in income taxes 8,462 (3,378) 1,270
---------------------------------------------------------------------------------------------------------------------------
Net change (11,333) 3,728 (460)
Balance - beginning of year 21,720 17,992 18,452
---------------------------------------------------------------------------------------------------------------------------
Balance - end of year $ 10,387 $ 21,720 $ 17,992
===========================================================================================================================
EXHIBIT 2
CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13A-14(A) OR 15D-14
OF THE SECURITIES EXCHANGE ACT OF 1934
CERTIFICATION
I, Steve W. Laut, certify that:
1. I have reviewed this annual report on Form 40-F of Canadian Natural
Resources Limited;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the issuer as of, and for, the periods presented in this report;
4. The issuer's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules 13(a) -
15(f) and 15d -15(f)) for the issuer and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
issuer, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, 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;
c) Evaluated the effectiveness of the issuer's disclosure controls and
procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the
end of the period covered by this report based on such evaluation;
and
d) Disclosed in this report any change in the issuer's internal control
over financial reporting that occurred during the period covered by
the annual report that has materially affected, or is reasonably
likely to materially affect, the issuer's internal control over
financial reporting; and
5. The issuer's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the issuer's auditors and the audit committee of issuer's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the issuer's ability to record,
process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the issuer's internal
control over financial reporting.
Dated this 25th day of March, 2009.
SIGNED " STEVE W. LAUT"
-----------------------
Steve W. Laut
President and Chief Operating Officer (Principal Executive Officer),
Canadian Natural Resources Limited
EXHIBIT 3
CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13A-14(A) OR 15D-14
OF THE SECURITIES EXCHANGE ACT OF 1934
CERTIFICATION
I, Douglas A. Proll, certify that:
1. I have reviewed this annual report on Form 40-F of Canadian Natural
Resources Limited;
2. Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the issuer as of, and for, the periods presented in this report;
4. The issuer's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules 13(a) -
15(f) and 15d -15(f)) for the issuer and have:
a) Designed such disclosure controls and procedures, or caused such
disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
issuer, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in
which this report is being prepared;
b) Designed such internal control over financial reporting, or caused
such internal control over financial reporting to be designed under
our supervision, 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;
c) Evaluated the effectiveness of the issuer's disclosure controls and
procedures and presented in this report our conclusion about the
effectiveness of the disclosure controls and procedures, as of the
end of the period covered by this report based on such evaluation;
and
d) Disclosed in this report any change in the issuer's internal control
over financial reporting that occurred during the period covered by
the annual report that has materially affected, or is reasonably
likely to materially affect, the issuer's internal control over
financial reporting; and
5. The issuer's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting,
to the issuer's auditors and the audit committee of issuer's board of
directors (or persons performing the equivalent functions):
a) All significant deficiencies and material weaknesses in the design
or operation of internal control over financial reporting which
are reasonably likely to adversely affect the issuer's ability to
record, process, summarize and report financial information; and
b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the issuer's
internal control over financial reporting.
Dated this 25th day of March, 2009.
SIGNED "DOUGLAS A. PROLL"
-----------------------------
Douglas A. Proll
Chief Financial Officer and Senior Vice-President, Finance
(Principal Financial Officer),
Canadian Natural Resources Limited
EXHIBIT 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)
In connection with the report of Canadian Natural Resources Limited (the
"Company") on the Form 40-F for the fiscal year ending December 31, 2008 as
filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I, Steve W. Laut, certify pursuant to 18 U.S.C. 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of
my knowledge:
1. The Report fully complies with the requirements of section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
DATED this 25th day of March, 2009.
SIGNED "STEVE W. LAUT"
----------------------
Steve W. Laut
President and Chief Operating Officer (Principal Executive Officer),
Canadian Natural Resources Limited
EXHIBIT 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)
In connection with the report of Canadian Natural Resources Limited (the
"Company") on the Form 40-F for the fiscal year ending December 31, 2008 as
filed with the Securities and Exchange Commission on the date hereof (the
"Report"), I, Douglas A. Proll, certify pursuant to 18 U.S.C. 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of
my knowledge:
1. The Report fully complies with the requirements of section 13(a) or 15(d)
of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the
Company.
DATED this 25th day of March, 2009.
SIGNED "DOUGLAS A. PROLL"
-------------------------
Douglas A. Proll
Chief Operating Officer and Senior Vice-President, Finance
(Principal Financial Officer),
Canadian Natural Resources Limited
EXHIBIT 6
CONSENT OF PRICEWATERHOUSECOOPERS LLP, INDEPENDENT CHARTERED ACCOUNTANTS
We hereby consent to (i) the inclusion in Canadian Natural Resources Limited's
Annual Report on Form 40-F for the year ended December 31, 2008; and (ii) the
incorporation by reference in the registration statement on Form F-9 (File No.
333-146056), of our audit report dated March 4, 2009 on the consolidated
balance sheets of Canadian Natural Resources Limited as at December 31, 2008
and 2007, and the consolidated statements of earnings, shareholder's equity,
comprehensive income and cash flows for each of the years in the three-year
period ended December 31, 2008 and the effectiveness of internal control over
financial reporting of Canadian Natural Resources Limited as of December 31,
2008.
Calgary, Alberta
March 25, 2009
EXHIBIT 7
CONSENT OF SPROULE ASSOCIATES LIMITED,
INDEPENDENT PETROLEUM ENGINEERING CONSULTANTS
We consent to the use of our report with respect to the reserves data of
Canadian Natural Resources Limited incorporated by reference in its (i) Annual
Report (Form 40-F) for the year ended December 31, 2008 and (ii) Registration
Statement on Form F-9 (Registration No. 333-146056) filed with the Securities
and Exchange Commission.
SIGNED "SPROULE ASSOCIATES LIMITED"
Calgary, Alberta
March 25, 2009
EXHIBIT 8
CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.,
INDEPENDENT PETROLEUM ENGINEERING CONSULTANTS
We consent to the use of our report with respect to the reserves data of
Canadian Natural Resources Limited incorporated by reference in its (i) Annual
Report (From 40-F) for the year ended December 31, 2008 and (ii) Registration
Statement on Form F-9 (Registration No. 333-146056) filed with the Securities
and Exchange Commission.
SIGNED "GLJ PETROLEUM CONSULTANTS LTD."
Calgary, Alberta
March 25, 2009