Edgar Filing: CANADIAN NATURAL RESOURCES LTD

form40f_2009.htm

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, 2009

Commission File Number: 333-12138

CANADIAN NATURAL RESOURCES LIMITED

(Exact name of Registrant as specified in its charter)

ALBERTA, CANADA

(Province or other jurisdiction of incorporation or organization)

1311

(Primary Standard Industrial Classification Code Numbers)

Not Applicable

(I.R.S. Employer Identification Number (if applicable))

2500, 855-2nd Street S.W., Calgary, Alberta, Canada, T2P 4J8

Telephone: (403) 517-7345

(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System, 111-Eighth Avenue, New York, New York 10011

(212) 894-8940

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of Each Class:	Name of each exchange on which registered:
Common Shares, no par value	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Title of Each Class: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this Form:

[ X ] Annual information form

[ X ] Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

542,327,240 Common Shares outstanding as of December 31, 2009

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 [ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (s.232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes __

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 (File No. 333-162270) 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, 2010, the noon buying rate for Canadian Dollars as expressed by the Federal Reserve Bank of New York was US$1.00 equals C$1.0283.

Principal Documents

The following documents have been filed as part of this Annual Report on Form 40-F, starting on the following page:

Annual Information Form

Annual Information Form of Canadian Natural Resources Limited (“Canadian Natural”) for the year ended December 31, 2009.

Audited Annual Financial Statements

Canadian Natural’s audited consolidated financial statements for the years ended December 31, 2009 and 2008, 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 17 of the notes to the audited consolidated financial statements.

Management’s Discussion and Analysis

Canadian Natural’s Management’s Discussion and Analysis for the year ended December 31, 2009.

Supplementary Oil & Gas Information

For Canadian Natural’s Supplementary Oil & Gas Information for the year ended December 31, 2009, see Exhibit 1 of this Annual Report on Form 40-F.

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2009

MARCH 25, 2010

TABLE OF CONTENTS

DEFINITIONS AND ABBREVIATIONS			4

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS			6

RISK FACTORS			8

ENVIRONMENTAL MATTERS			12

REGULATORY MATTERS			13

THE COMPANY			15

GENERAL DEVELOPMENT OF THE BUSINESS			17

DESCRIPTION OF THE BUSINESS			18

A.	PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES		19

		Daily Production	19
		Developed and Undeveloped Acreage	20
		Drilling Activity	21
		Productive Crude Oil and Natural Gas Wells	24
		Northeast British Columbia	24
		Northwest Alberta	25
		Northern Plains	26
		Southern Plains and Southeast Saskatchewan	28
		Oil Sands Mining and Upgrading	29
		United Kingdom North Sea	33
		Offshore West Africa	34
		Côte d’Ivoire	34
		Gabon	35

B.	CRUDE OIL, NGLs AND NATURAL GAS RESERVES		36

C.	RECONCILIATION OF CHANGES IN NET RESERVES		42

D.	CRUDE OIL, NGLs AND NATURAL GAS PRODUCTION		46

E.	NET CAPITAL EXPENDITURES		51

F.	DEVELOPED AND UNDEVELOPED ACREAGE		52

SELECTED FINANCIAL INFORMATION			53

CAPITAL STRUCTURE			54

MARKET FOR CANADIAN NATURAL RESOURCES LIMITED SECURITIES			55

DIVIDEND HISTORY			56

TRANSFER AGENTS AND REGISTRAR			56

DIRECTORS AND OFFICERS			57

Canadian Natural Resources Limited

CONFLICTS OF INTEREST			61

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			61

AUDIT COMMITTEE INFORMATION			62

LEGAL PROCEEDINGS			63

MATERIAL CONTRACTS			63

INTERESTS OF EXPERTS			63

ADDITIONAL INFORMATION			63

SCHEDULE “A” REPORT ON RESERVES DATA			64

SCHEDULE “B” REPORT OF MANAGEMENT AND DIRECTORS			66

SCHEDULE “C” CHARTER OF THE AUDIT COMMITTEE			68

3	Canadian Natural Resources Limited

DEFINITIONS AND ABBREVIATIONS

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”, “Company”, or “Corporation” 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

“crude oil, NGLs and natural gas” includes all of the Company’s crude oil, synthetic crude oil, bitumen, coal bed methane, NGLs and natural gas reserves

“development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive

“dry well” means an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well

“exploratory well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir

“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 has a working interest

“gross wells” means the total number of wells in which the Company has a working interest

“Horizon” means Horizon Oil Sands

“mbbl” means one thousand barrels

“mcf” means one thousand cubic feet

“mcf/d” means one thousand cubic feet per day

“mmbbl” means one million barrels

“mmbtu” means one million British thermal units

“mmcf” means one million cubic feet

Canadian Natural Resources Limited

“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

“net asset value” means the discounted pre-tax value of forecast price proved and probable crude oil and natural gas reserves (net of future development costs and associated material well abandonment costs) plus the value of core undeveloped land, less net debt.

“net wells” refers to gross wells multiplied by the percentage working interest therein owned by the Company

“NYSE” means New York Stock Exchange

“productive well” means an exploratory, development or extension well that is not dry

“PRT” means Petroleum Revenue Tax

“SAGD” means Steam-Assisted Gravity Drainage

“SCO” means Synthetic Crude Oil

“SEC” means United States Securities and Exchange Commission

“TSX” means Toronto Stock Exchange

“undeveloped acreage” refers to lands on which wells have not been drilled or completed to a point that would permit the production of economic quantities of crude oil and natural gas regardless of whether such acreage contains proved reserves.

“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 relating to the Company 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 in the 2010 outlook section and throughout this document and the documents incorporated herein by reference constitute forward looking statements. Disclosure of plans relating to existing and future developments including but not limited to Horizon, Primrose East, Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal 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. 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 risks and uncertainties 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

Special Note Regarding Currency, Production and Reserves

In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves data is presented on a net of royalties basis 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, 2009, the Company retained qualified independent reserves evaluators, Sproule Associates Limited (“Sproule”), and GLJ Petroleum Consultants Ltd. (“GLJ”), to evaluate and review all of the Company’s proved, as well as probable crude oil, synthetic crude oil, bitumen, coal bed methane, NGLs and natural gas reserves and prepare Evaluation Reports on these reserves. Sproule evaluated and reviewed all of the Company’s crude oil, bitumen, natural gas, coal bed methane and NGLs reserves. GLJ evaluated all of the synthetic crude oil reserves related to the Company’s oil sands mine. The Company has been granted an exemption from certain 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 under Regulations S-K and S-X for certain disclosures required under NI 51-101. On December 31, 2008, the SEC released its final rules for the modernization of oil and gas reporting (“Final Rule”). The material changes include the ability to include oil sands mining as an oil and gas activity, ability to use reliable technology to establish undeveloped reserves, the optional ability to report probable reserves, the requirement to track undeveloped locations, as well as the directive to use 12-month average prices and current costs. These resulting changes are more in line with NI 51-101 however there are material differences to the type of volumes disclosed and the basis from which the volumes are determined. NI 51-101 requires gross reserves and future net revenue under forecast pricing and costs, however, the SEC, as discussed, requires disclosure of net reserves, after royalties, under 12-month average prices and current costs. The difference between the reported numbers under the two disclosure standards can be material.

The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with Sproule and GLJ as to the Company’s reserves.

The Company annually discloses proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current 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.

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.

7	Canadian Natural Resources Limited

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 Horizon, Primrose East, Pelican Lake, Olowi Field (Offshore Gabon), and the Kirby Thermal 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 the Company’s financial condition.

Approximately 26% of the Company’s 2009 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 financial condition.

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.

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

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, NGLs, natural gas, 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 crude 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 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 the Company’s financial condition.

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 may 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 in favour of less energy intensive sources, may have a material adverse effect on the Company’s financial condition.

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 the form of regulation, 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, compressor optimization to improve fuel gas efficiency, 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 the near term to address industrial GHG emissions, as part of the national GHG reduction target. 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. The British Columbia carbon tax is currently being assessed at $15/tonne of CO2e on fuel consumed and gas flared in the province. This rate is scheduled to increase to $20/tonne on July 1, 2010, and to $30/tonne by July 1, 2012. As part of its involvement with the Western Climate Initiative, British Columbia has also announced that certain upstream oil and gas facilities will be included in a regional cap and trade system beginning in 2012. It is estimated that six facilities in BC will be included under the cap and trade system, based on a proposed 25 kilotonne of CO2e threshold. Saskatchewan is expected to release GHG regulation in 2010 that may require the North Tangleflags in-situ heavy oil facility to meet a reduction target for its GHG emissions intensity. 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 compliance costs to the Company relating to the above regulations for 2009 are approximately $26 million.

Legislation to regulate GHGs in the United States through a cap and trade system is currently before the US Congress, although there is no certainty as to the form or stringency of the final legislation. In the absence of legislation, the US Environmental Protection Agency (EPA) is authorized under the Clean Air Act to regulate GHGs, although EPA action would be subject to legal and political challenges. The ultimate form of Canadian regulation is anticipated to be strongly influenced by the regulatory decisions made within the US. Various states have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oils with higher emissions intensity.

The additional requirements of enacted or proposed GHG legislation on the Company’s operations will increase capital expenditures and production expense, especially those related to Horizon and the Company’s other existing and planned large oil sands projects. Depending on the legislation enacted, this may have an adverse effect on the Company’s financial condition.

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 also result in royalties being paid on a reference price which is higher than the hedged price. There is also increased exposure to counterparty credit risk.

Canadian Natural Resources Limited

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 Horizon operations are subject to loss of production, potential shutdowns and increased production costs due to the integration of the various component parts, as well as severe winter weather conditions.

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 utilized for the payment of funds to the Company. In the event of the liquidation of any corporate subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used by the Company to pay its indebtedness.

11	Canadian Natural Resources Limited

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 conservation program; a program to replace the majority of fresh water for steaming with brackish water; water management programs to improve efficiency of use, recycle rates and water storage; 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; continued evaluation of new technologies to reduce environmental impacts; development of a tailings management plan; and CO2 reduction programs including the injection of CO2 into tailings and for use in enhanced oil recovery. The Company has also established operating standards in the following areas: 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 offshore through cost-effective measures. Canadian Natural participates in both the Canadian federal and provincial regulated GHG emissions reporting 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. Canadian Natural continues to invest in proven and new technologies and in improved operating strategies to help us achieve the Company’s overall GHG management goals.

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. 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 continues to focus on reducing GHG emissions through improved efficiency, and on trading mechanisms to ensure compliance with requirements 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 six core principles: improving energy conservation and efficiency; reducing emission intensity; developing and adopting innovative technology and supporting associated research and development; trading capacity, both domestically and globally; offsetting emissions; and considering life cycle costs of emission reductions in decision-making about project development.

The Company continues to implement flaring, venting and fuel and solution gas conservation programs. In 2009 the Company completed approximately 93 gas conservation projects in its primary heavy oil operations, resulting in a reduction of 1.35 million tonnes/year of CO2e. Over the past five years the Company has spent over $64.3 million in its primary heavy crude oil and in-situ oil sands operations to conserve the equivalent of over 8.7 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. Horizon 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 oil sands tailings.

Canadian Natural Resources Limited

In its North Sea operations the Company continues to focus on implementing reduction programs based on efficiency audits of its major facilities. A number of CO2 reduction initiatives were carried out in 2009 including turbine washing on Ninian Northern Platform and an operational focus on reducing flaring. The Produced Water Re-injection on Ninian Central was made permanent in 2008. The Company continues to work at improving produced water quality and reducing oil discharged to sea.

For 2009, the Company’s capital expenditures included $48 million for abandonment expenditures (2008 - $38 million).

The Company’s estimated undiscounted ARO at December 31, 2009 was as follows:

Estimated ARO, undiscounted ($millions)	2009			2008
North America	$	3,346		$	3,072
Oil Sands Mining and Upgrading (1)		1,485			93
North Sea		1,522			1,216
Offshore West Africa		253			93
		6,606			4,474
North Sea PRT recovery		(568	)		(529	)
	$	6,038		$	3,945

(1)	Prior period amounts have been reclassified to conform to the presentation adopted in 2009.

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 $568 million (2008 - $529 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 $6,038 million (2008 - $3,945 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 crude oil 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.

13	Canadian Natural Resources Limited

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. 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.

Effective January 1, 2009, changes were made to the Alberta royalty regime under the Alberta Royalty Framework (“ARF”). The ARF includes a number of changes to royalty rates for natural gas, conventional crude oil, and oil sands production. Under the ARF, royalties payable are variable according to commodity prices and the productivity and depth of wells. The ARF 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 ARF 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 March 2009, the Government of Alberta announced new incentive programs to stimulate activity in Alberta. These programs provide for:

●	A royalty credit of $200 per meter on new conventional crude oil and natural gas wells drilled between April 1, 2009 and March 31, 2010 to a maximum of 10% of conventional Crown royalties paid in Alberta.

●	Reduced royalty rates that set the maximum royalty at 5% for the first 12 months of production, up to a maximum of 50,000 boe or 500 mmcfe for new conventional crude oil and natural gas wells that commence production between April 1, 2009 and March 31, 2010.

In June 2009, the Government of Alberta extended the two incentive programs described above by one year, to

March 31, 2011.

In March 2010, the Government of Alberta further modified the conventional oil and natural gas royalty rates. These changes, effective January 1, 2011, include:

●	Permanently imbedding in the royalty system the reduced royalty rate of a maximum of 5% on new natural gas and conventional oil wells with the same time and volume limits.

●	Reducing the maximum royalty rate for conventional crude oil from 50% to 40% and reducing the maximum royalty rate for conventional and unconventional gas from 50% to 36%.

All royalty curves are to be finalized and announced by May 31, 2010.

Effective September 1, 2009, the Province of British Columbia announced an oil and gas stimulus package that includes:

●	A one-year, 2% royalty rate for all natural gas wells drilled between September 1, 2009 and June 30, 2010. Qualifying wells must commence production before December 31, 2010.

●	A permanent increase of 15% in the existing royalty holiday credits for the Deep Royalty Program.

●	A permanent qualification of horizontal wells drilled to a vertical depth between 1,900 and 2,300 meters into the Deep Royalty Program.

●	An additional $50 million allocation for the Infrastructure Royalty Credit Programs to stimulate investment in oil and gas roads and pipelines.

In addition to government royalties, the Company is subject to federal and provincial income taxes in Canada at a combined rate of approximately 29% after allowable deductions for 2009.

During 2007, the Canadian Federal Government enacted income tax rate changes which decrease the Federal corporate income tax rate over a five year period. The income tax rate in 2009 was 19%, is 18% in 2010 and decreases to 15% in 2012.

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 Côte 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 Côte 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 (“ACC”), a subsidiary of Anadarko Petroleum Corporation. On November 3, 2006, ACC 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.

15	Canadian Natural Resources Limited

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:

	Jurisdiction of Incorporation	% Ownership
Subsidiary
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 Côte d’Ivoire SARL	Côte d’Ivoire	100
CNR International (Olowi) Limited	Bahamas	100
Horizon Construction Management Ltd.	Alberta	100
Partnership
Canadian Natural Resources Partnership	Alberta	100
Canadian Natural Resources Northern Alberta Partnership	Alberta	100
Canadian Natural Resources 2005 Partnership	Alberta	100

Canadian Natural, as the managing partner, CNR (ECHO) Resources Inc. and Canadian Natural Resources 2005 Partnership are the partners of Canadian Natural Resources, a general partnership. Canadian Natural, as the managing partner, CNR (ECHO) Resources Inc., Canadian Natural Resources and Canadian Natural Resources 2005 Partnership are partners of Canadian Natural Resources Northern Alberta Partnership, a general partnership. Canadian Natural, as the managing partner, and CNR (ECHO) Resources Inc. are the partners of Canadian Natural Resources 2005 Partnership.

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.

Canadian Natural Resources Limited

GENERAL DEVELOPMENT OF THE BUSINESS – THREE YEAR HISTORY

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.

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 $71 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 27 transactions to dispose of non-core operated and non-operated properties for proceeds of $110 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. Deliveries under the agreements are expected to commence in 2012 contingent upon Keystone receiving the regulatory approvals for the pipeline expansion and subsequent completion of the expansion.

The Company entered into an agreement in August 2005 to obtain pipeline transportation service for Horizon. 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 site down to the AOSPL Terminal (collectively, the “Horizon Pipeline”) will provide crude oil transportation service for Horizon. 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 SCO transportation service for Horizon, while at the same time providing significant quality benefits associated with being the only shipper on the Horizon Pipeline.

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 $356 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 22 transactions to dispose of non-core operated and non-operated properties for proceeds of $20 million.

2009

Construction of Phase 1 of Horizon was completed and commercial operations began.

The Company repaid the $2,350 million remaining on the non-revolving syndicated credit facility related to the 2006 acquisition of ACC and cancelled the facility.

The Company completed 59 transactions in the normal course to acquire additional interests in crude oil and natural gas properties. The aggregate net expenditure of the transactions was $42 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 24 transactions to dispose of non-core operated and non-operated properties and seismic for proceeds of $36 million.

17	Canadian Natural Resources Limited

2010 Outlook

In January 2010, the Company announced that, together with North West Upgrading Inc. (“NWU”), it had submitted a joint proposal to the Alberta Government to construct and operate a bitumen refinery near Redwater, Alberta. This proposal was submitted in response to a request for proposal under the Alberta Royalty Framework’s Bitumen Royalty in Kind (BRIK) program. Canadian Natural agreed, subject to a number of conditions, to acquire 50% of the assets of NWU and form a partnership to construct and operate the facility. Closing of the acquisition is targeted for later in 2010 and remains subject to the satisfaction of a number of conditions. Phase 1 of the proposed facility includes a one step conversion process of 50,000 bbl/d of bitumen to finished products and an integrated CO2 management solution. The proposed facility can be expanded in two additional identical phases of 50,000 bbl/d of bitumen, provided economics justify the investment. Canadian Natural has agreed to supply 12,500 bbl/d of its own bitumen production to Phase 1 of the proposed facility.

For 2010, the Company’s overall conventional drilling activity in North America is expected to comprise approximately 93 natural gas wells and 966 crude oil wells, excluding stratigraphic and service wells. Conventional capital expenditures in North America for 2010 are currently expected to be approximately $2.6 billion, excluding property acquisitions and dispositions. Capital expenditures related to Oil Sands Mining and Upgrading are expected to be $738 million excluding capitalized interest.

For 2010, capital expenditures in the North Sea are estimated to be $199 million and are expected to be $264 million for Offshore West Africa.

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, and natural gas 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, 2009, the Company had 3,827 full time equivalent permanent employees in North America and 337 full time equivalent permanent employees in its international operations.

The Company focuses on exploiting its core properties and actively maintaining cost controls. Whenever possible Canadian Natural maintains 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 (14-17º API oil, which receives medium quality crude netbacks due to lower production costs and lower royalty rates), primary heavy crude oil, thermal heavy crude oil and SCO. The Company’s operations are centered 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 38% of 2009 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 21% of 2009 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 26% of 2009 production. SCO accounts for approximately 9% of 2009 production. Pelican Lake crude oil, which accounts for 6% of 2009 production, is produced from the Pelican Lake area in northern 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 11 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.

Canadian Natural Resources Limited

A.	PRINCIPAL CRUDE OIL AND NATURAL GAS PROPERTIES

Daily Production

Set forth below is a summary of the crude oil, NGLs and natural gas properties for the fiscal years ended December 31, 2009 and 2008.

	2009 Average Daily Production Rates		2008 Average Daily Production Rates
Region	Crude oil & NGLs (mbbl)	Natural gas (mmcf)	Crude oil & NGLs (mbbl)	Natural gas (mmcf)
North America
Northeast British Columbia	5.5	329	5.9	377
Northwest Alberta	14.8	455	16.4	531
Northern Plains	194.6	341	200.7	382
Southern Plains	11.4	158	12.2	177
Southeast Saskatchewan	7.9	3	8.4	3
Oil sands Mining & Upgrading	50.3	-	-	-
Non-core regions	0.3	1	0.2	2
North America Total	284.8	1,287	243.8	1,472
International
North Sea UK Sector	37.8	10	45.3	10
Offshore West Africa
Côte d’Ivoire	30.3	18	26.6	13
Gabon	2.6	-	-	-
International Total	70.7	28	71.9	23
Company Total	355.5	1,315	315.7	1,495

19	Canadian Natural Resources Limited

Developed and Undeveloped Acreage

The following table summarizes the Company’s landholdings as at December 31, 2009.

	Developed Acreage		Undeveloped Acreage		Total Acreage		Average Working Interest
Region (thousands of acres)	Gross	Net	Gross	Net	Gross	Net	%
North America
Northeast British Columbia	1,493	1,132	2,838	2,068	4,331	3,200	74
Northwest Alberta	1,229	883	1,531	1,154	2,760	2,037	74
Northern Plains	4,111	3,351	6,696	5,885	10,807	9,236	85
Southern Plains	1,530	1,216	950	804	2,480	2,020	81
Southeast Saskatchewan	93	76	154	139	247	215	87
Thermal In-Situ Oil Sands	29	29	588	486	617	515	83
Oil Sands Mining & Upgrading	1	1	115	115	116	116	100
Non-core regions	42	14	1,341	201	1,383	215	16
North America Total	8,528	6,702	14,213	10,852	22,741	17,554	77
International
North Sea UK Sector	68	57	184	150	252	207	82
Offshore West Africa
Côte d’Ivoire	10	6	92	54	102	60	59
Gabon	2	2	150	138	152	140	92
Non-core regions
South Africa	-	-	4,002	4,002	4,002	4,002	100
International Total	80	65	4,428	4,344	4,508	4,409	98
Company Total	8,608	6,767	18,641	15,196	27,249	21,963	81

Canadian Natural Resources Limited

Drilling Activity

Set forth below are summaries of crude oil, NGLs and natural gas drilling activities of the Company for the fiscal years ended December 31, 2009, 2008 and 2007 by geographic region.

						2009
		Exploratory					Development
		Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total	Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total
North America
Northeast British Columbia	Gross	-	1.0	3.0	-	4.0	-	20.0	1.0	-	21.0
Northeast British Columbia	Net	-	0.5	2.4	-	2.9	-	17.6	1.0	-	18.6
Northwest Alberta	Gross	4.0	24.0	-	-	28.0	4.0	24.0	1.0	-	29.0
Northwest Alberta	Net	3.5	22.3	-	-	25.8	3.3	23.4	1.0	-	27.7
Northern Plains	Gross	39.0	8.0	6.0	7.0	60.0	601.0	37.0	35.0	203.0	876.0
Northern Plains	Net	38.5	7.1	6.0	7.0	58.6	565.9	27.9	33.5	203.0	830.3
Southern Plains	Gross	3.0	2.0	1.0	-	6.0	5.0	25.0	1.0	1.0	32.0
Southern Plains	Net	2.1	2.0	1.0	-	5.1	3.6	8.3	1.0	1.0	13.9
Southeast Saskatchewan	Gross	3.0	-	-	-	3.0	20.0	-	-	2.0	22.0
Southeast Saskatchewan	Net	2.1	-	-	-	2.1	18.4	-	-	2.0	20.4
Oil Sands Mining and Upgrading	Gross	-	-	-	-	-	-	-	-	115.0	115.0
Oil Sands Mining and Upgrading	Net	-	-	-	-	-	-	-	-	115.0	115.0
Non-core Regions	Gross	-	-	-	-	-	-	-	-	-	-
Non-core Regions	Net	-	-	-	-	-	-	-	-	-	-
North America Total	Gross	49.0	35.0	10.0	7.0	101.0	630.0	106.0	38.0	321.0	1,095.0
North America Total	Net	46.2	31.9	9.4	7.0	94.5	591.2	77.2	36.5	321.0	1,025.9
North Sea UK Sector	Gross	-	-	1.0	-	1.0	1.0	-	-	-	1.0
North Sea UK Sector	Net	-	-	0.3	-	0.3	0.9	-	-	-	0.9
Offshore West Africa	Gross	-	-	-	-	-	6.0	-	-	1.0	7.0
Offshore West Africa	Net	-	-	-	-	-	5.2	-	-	0.9	6.1
Company Total	Gross	49.0	35.0	11.0	7.0	102.0	637.0	106.0	38.0	322.0	1,103.0
Company Total	Net	46.2	31.9	9.7	7.0	94.8	597.3	77.2	36.5	321.9	1,032.9

Total success rate excluding service and stratigraphic test wells for 2009 is 94% (2008 - 96%, 2007 - 91%)

At December 31, 2009, Canadian Natural was in the process of drilling 10 gross wells (9.5 net wells) in Canada and 1 gross well (0.93 net wells) in Offshore West Africa.

21	Canadian Natural Resources Limited

						2008
		Exploratory					Development
		Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total	Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total
North America
Northeast British Columbia	Gross	-	2.0	2.0	-	4.0	-	26.0	4.0	-	30.0
Northeast British Columbia	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
Northwest Alberta	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
Northern Plains	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
Southern Plains	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
Southeast Saskatchewan	Net	4.6	-	2.0	-	6.6	48.9	-	-	1.7	50.6
Oil Sands Mining and Upgrading	Gross	-	-	-	-	-	-	-	-	92.0	92.0
Oil Sands Mining and Upgrading	Net	-	-	-	-	-	-	-	-	92.0	92.0
Non-core Regions	Gross	-	-	-	-	-	-	3.0	2.0	-	5.0
Non-core Regions	Net	-	-	-	-	-	-	0.1	0.4	-	0.5
North America Total	Gross	38.0	36.0	11.0	-	85.0	683.0	375.0	32.0	130.0	1,220.0
North America Total	Net	35.5	31.5	10.4	-	77.4	642.0	237.8	27.4	128.3	1,035.5
North Sea UK Sector	Gross	1.0	-	-	-	1.0	2.0	-	1.0	1.0	4.0
North Sea UK Sector	Net	0.8	-	-	-	0.8	1.6	-	0.8	0.9	3.3
Offshore West Africa	Gross	-	-	-	-	-	4.0	-	-	2.0	6.0
Offshore West Africa	Net	-	-	-	-	-	2.3	-	-	1.8	4.1
Company Total	Gross	39.0	36.0	11.0	-	86.0	689.0	375.0	33.0	133.0	1,230.0
Company Total	Net	36.3	31.5	10.4	-	78.2	645.9	237.8	28.2	131.0	1,042.9

Canadian Natural Resources Limited

						2007
		Exploratory					Development
		Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total	Crude Oil	Natural Gas	Dry	Service/ Stratigraphic	Total
North America
Northeast British Columbia	Gross	-	7.0	7.0	-	14.0	3.0	45.0	12.0	-	60.0
Northeast British Columbia	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
Northwest Alberta	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
Northern Plains	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
Southern Plains	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
Southeast Saskatchewan	Net	1.0	-	-	-	1.0	23.0	-	0.4	4.0	27.4
Oil Sands Mining and Upgrading	Gross	-	-	-	-	-	-	-	-	98.0	98.0
Oil Sands Mining and Upgrading	Net	-	-	-	-	-	-	-	-	98.0	98.0
Non-core Regions	Gross	-	-	-	-	-	-	-	-	-	-
Non-core Regions	Net	-	-	-	-	-	-	-	-	-	-
North America Total	Gross	29.0	75.0	33.0	97.0	234.0	615.0	403.0	74.0	154.0	1,246.0
North America Total	Net	26.8	61.5	30.2	97.0	215.5	556.7	322.2	62.4	153.3	1,094.6
North Sea UK Sector	Gross	-	-	-	-	-	4.0	-	-	4.0	8.0
North Sea UK Sector	Net	-	-	-	-	-	3.7	-	-	3.5	7.2
Offshore West Africa	Gross	-	-	-	-	-	7.0	-	-	1.0	8.0
Offshore West Africa	Net	-	-	-	-	-	4.1	-	-	0.6	4.7
Company Total	Gross	29.0	75.0	33.0	97.0	234.0	626.0	403.0	74.0	159.0	1,262.0
Company Total	Net	26.8	61.5	30.2	97.0	215.5	564.5	322.2	62.4	157.4	1,106.5

23	Canadian Natural Resources Limited

Productive Crude Oil & Natural Gas Wells

Set forth below is a summary of the number of gross and net wells of the Company that were producing or mechanically capable of producing as of December 31, 2009.

		Natural gas wells			Crude oil wells			Total wells
	Gross		Net	Gross		Net	Gross		Net
Canada
Northeast British Columbia	1,545		1,281.2	218		187.4	1,763		1,468.6
Northwest Alberta	2,138		1,677.5	555		342.4	2,693		2,019.9
Northern Plains	3,788		3,077.9	6,009		5,529.6	9,797		8,607.5
Southern Plains	7,366		6,094.4	1,227		1,121.5	8,593		7,215.9
Southeast Saskatchewan	-		-	1,198		876.6	1,198		876.6
Non-core regions	77		20.9	121		24.8	198		45.7
Total Canada	14,914		12,151.9	9,328		8,082.3	24,242		20,234.2
United States	3		0.3	2		0.3	5		0.6
North Sea UK Sector	2		0.1	108		91.1	110		91.2
Offshore West Africa
Gabon	-		-	5		4.6	5		4.6
Côte d’Ivoire	-		-	23		13.4	23		13.4
Total	14,919		12,152.3	9,466		8,191.7	24,385		20,344.0

Any reserves data in the following property report is based on the applicable independent engineering report. See the section entitled “Crude Oil, NGLs and Natural Gas Reserves” in this Annual Information Form.

Northeast British Columbia

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

Canadian Natural Resources Limited

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.

Northwest Alberta

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 RAX; subsequent to 2002 the Company augmented these holdings with additional land purchases, acquisitions and in 2006 the purchase of the ACC assets. The ACC acquisition added two very prospective properties to this region, Wild River and Peace River Arch. The Wild River assets 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.

25	Canadian Natural Resources Limited

Northern Plains

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°-14° API) and natural gas are produced through conventional vertical, slant and horizontal well bores from a number of productive horizons at depths up to 1,000 meters. 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 crude oil production are the result of Crown land purchases and several acquisitions including Sceptre, Ranger 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.

Canadian Natural Resources Limited

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°-17° 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 28% of the field has been converted to waterflood and there are 227 polymer injection wells supporting approximately 259 production wells. Pelican Lake production averaged approximately 37,000 bbl/d in 2009 (2008-37,000 bbl/d). The Company is continuing to drill and convert wells in 2010 and anticipates approximately 40% of the field will be converted to polymer injection by the end of 2010.

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°-11°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. Canadian Natural is proceeding with the detailed engineering and design work and project sanction and scope is targeted for late 2010.

In 2007, the Company received regulatory approval for its Primrose East expansion, 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. During the first quarter of 2009, 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 formalized and received approval for a plan to begin diagnostic steaming which commenced in August 2009 and is proceeding according to plan with steaming targeted to ramp up again in 2010.

27	Canadian Natural Resources Limited

Southern Plains and Southeast Saskatchewan

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

Oil Sands Mining and Upgrading

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. Horizon is located on these leases, about 70 kilometers north of Fort McMurray. Figure 1 shows the location of Horizon within Alberta and within the region. Figure 2 shows the mining area associated with the reserves and the general layout of the site. Table 1 describes the leases the Company holds in the region.

Figure 1 - Location of Horizon Oil Sands

29	Canadian Natural Resources Limited

Figure 2 - Horizon Oil Sands Resource Areas and General Layout

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 6	7597050T06	May 6, 2012	2,584
Lease 7	7597050T07	May 6, 2012	1,144
Lease 10	7400120010	December 14, 2015	3,840
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 25	7401050025	May 17, 2016	1,536
Lease 19	7402050019	May 30, 2017	5,120
Lease 20	7402050020	May 30, 2017	768

(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 Horizon are 18, 25, 10, 19 and 20. The site is accessible by a private road as well as a private airstrip.

Horizon Oil Sands 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 34o API SCO. The upgrader capacity is 110,000 bbl/day of SCO. The SCO is transported from the site by the Horizon Pipeline with a design capacity of 232,000 bbl/day to the Edmonton area for distribution. An on-site cogeneration plant with a design capacity of 115 MW provides power and steam for the operation.

In June 2002, Canadian Natural filed an application with the Energy Resources Conservation Board (ERCB) (formerly the Alberta Energy and Utilities Board) for regulatory approval of Horizon. 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”) established by the ERCB and the Government of Canada examined the project in a public hearing in September 2003. The Panel issued its decision report in January 2004, finding Horizon was in the public interest. An Alberta Order-in-Council approval was received from the ERCB 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. In 2009, Canadian Natural submitted an administrative amendment to its ERCB approval to incorporate changes to development timing at Horizon and approval is expected in 2010. A Tailings Management Plan was also submitted to the ERCB in September 2009 and approval is expected in 2010.

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 Horizon.

First SCO production was achieved during 2009 and the Company continues to ramp up to sustainable production of 110,000 bbl/d of SCO which is expected to be achieved in 2010.

Engineering and procurement for Tranche 2 of the Phase 2/3 expansion is progressing with a focus on increasing reliability and uptime. Tranches 3 and 4 of Phase 2/3 continue to be re-profiled with the Company continuing to work on completing its lessons learned from the construction of Phase 1 and implementing these into the development of future expansions.

Regional and Horizon Oil Sands Geology

Lease 18, the main oil sands lease for Horizon, 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.

31	Canadian Natural Resources Limited

In the area of Horizon, 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 clays that reside above the unconformity with the underlying Upper Devonian carbonates (limestone) of the Waterways Formation. The McMurray Formation at the site of Horizon 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 Horizon’s oil sands resource is found within the lower and middle McMurray. The general stratigraphy of Horizon is shown in Figure 3.

Figure 3 - General Stratigraphy of Horizon

Canadian Natural Resources Limited

United Kingdom North Sea

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 2009, 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 an 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 2009, one production well was completed at Ninian. The Company continued to focus on maturing and high grading infill drilling opportunities in preparation for the restart of platform drilling operations in the second quarter of 2010.

The Company continued with its planned investment in its long-term facilities and infrastructure strategy and successfully carried out maintenance turnarounds at four of the five installations during the year.

In the first quarter 2009, the Company commenced drilling on Deep Banff a high temperature, high pressure, natural gas exploration well which did not find commercial hydrocarbons and was plugged and abandoned early in the third quarter of 2009.

33	Canadian Natural Resources Limited

Offshore West Africa

Côte d’Ivoire

The Company owns interests in two exploration licences offshore Côte 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 processing capacity of the FPSO has reverted to the original schedule to accommodate effective utilization of the installation vessel at the Olowi Field. Commissioning is targeted to be complete during the second quarter of 2010.

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 2008. A fourth and final well was completed in the second quarter of 2009.

To date political unrest, which has occurred from time to time in Côte d’Ivoire, has had no impact on the Company’s operations. The Company has developed contingency plans to continue Côte d’Ivoire operations from a nearby country if the situation warrants such a move.

Canadian Natural Resources Limited

Gabon

The Company has a permit comprising a 92.5% 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, resulted in first oil commencing in the second quarter of 2009. Production to date from the first platform is below expectations. The Company is currently reviewing drilling results and production data in order to develop appropriate remediation strategies and determine the impact on future production from the field, the impact on recoverable reserves and the scope of the overall development plan. The Company continues drilling the next scheduled platform with production targeted for the second quarter of 2010.

35	Canadian Natural Resources Limited

B.	CRUDE OIL, NGLs, AND NATURAL GAS RESERVES

The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with Sproule and GLJ as to the Company’s reserves.

There is no assurance that the price and cost assumptions contained in either the 12-month average case or forecast case will be attained and variances could be material.

In the ordinary course of business, the Company has a number of delivery commitments to provide crude oil and natural gas under existing contracts and agreements. The Company has sufficient crude oil and natural gas reserves to meet these commitments.

Canadian Natural Resources Limited

Summary of Crude Oil, NGLs and Natural Gas Net Reserves

The following tables summarize the evaluations of the reserves as at December 31, 2009.

Reserves Category	Crude Oil & NGLs (mmbbl)	Bitumen (mmbbl)	Synthetic Crude Oil (mmbbl)	Total Liquids (mmbbl)	Natural Gas (bcf)	Total Reserves (mmboe)
PROVED
Developed:
North America	204	268	1,589	2,061	2,333	2,450
International
United Kingdom – North Sea	94	-	-	94	45	101
Offshore West Africa	106	-	-	106	81	120
Total Developed:	404	268	1,589	2,261	2,459	2,671

Undeveloped:
North America	115	427	61	603	694	719
International
United Kingdom – North Sea	146	-	-	146	22	149
Offshore West Africa	17	-	-	17	4	18
Total Undeveloped:	278	427	61	766	720	886
TOTAL PROVED:	682	695	1,650	3,027	3,179	3,557

37	Canadian Natural Resources Limited

Reserves Category	Crude Oil & NGLs (mmbbl)	Bitumen (mmbbl)	Synthetic Crude Oil (mmbbl)	Total Liquids (mmbbl)	Natural Gas (bcf)	Total Reserves (mmboe)
PROBABLE
Developed:
North America	72	23	79	174	709	292
International
United Kingdom – North Sea	35	-	-	35	8	36
Offshore West Africa	5	-	-	5	26	9
Total Developed:	112	23	79	214	743	337

Undeveloped:
North America	56	495	783	1,334	256	1,377
International
United Kingdom – North Sea	112	-	-	112	19	116
Offshore West Africa	51	-	-	51	13	53
Total Undeveloped:	219	495	783	1,497	288	1,546
TOTAL PROBABLE:	331	518	862	1,711	1,031	1,883

Undeveloped Reserves

The Company’s proved undeveloped reserves make up 25% of our 3,557 mmboe proved reserves. In 2009, the Company spent $774 million to convert 135 mmboe of pre-existing undeveloped reserves to developed reserves. The total estimated future capital, based on 2009 costs, required to develop the Company’s 886 mmboe proved undeveloped reserves is $9.4 billion dollars. The total estimated future capital, based on 2009 costs, required to develop the Company’s 1,546 mmboe of probable undeveloped reserves is $3.5 billion dollars.

Reserves which have remained undeveloped for 5 years or more are 363 mmboe of proved undeveloped and 404 mmboe of probable undeveloped. Of these reserves, 354 mmboe proved undeveloped and 402 mmboe probable undeveloped are associated with our long life large project thermal reserves. The remaining undeveloped reserves are associated with our offshore international projects and future uphole potential reserves associated with existing producing well bores.

Canadian Natural Resources Limited

Sensitivity of Reserves to Prices by Principal Product Type

Price Case	Proved Reserves
	Crude Oil & NGLs (mmbbl)	Bitumen (mmbbl)	Synthetic Crude Oil (mmbbl)	Total Liquids (mmbbl)	Natural Gas (bcf)	Total Reserves (mmboe)
December 31, 2009 Forecast Pricing	684	652	1,564	2,900	3,491	3,482

Price Case	Probable Reserves
	Crude Oil & NGLs (mmbbl)	Bitumen (mmbbl)	Synthetic Crude Oil (mmbbl)	Total Liquids (mmbbl)	Natural Gas (bcf)	Total Reserves (mmboe)
December 31, 2009 Forecast Pricing	295	482	820	1,597	1,174	1,793

NOTES

1.	“Net” reserves mean the Company’s gross reserves less all royalties payable to others plus royalties receivable from others.

Bitumen as defined by the SEC, under the Final Rule, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all the Company’s primary and thermal heavy crude oil reserves have been reclassified as bitumen. Prior to December 31, 2009, these reserves would have been classified within the Company’s conventional crude oil and NGLs totals.

Prior to December 31, 2009, the Company’s Horizon SCO reserves were reported separately in accordance to the SEC’s Industry Guide 7. With SEC’s Final Rule in effect January 1, 2010, for fiscal years ending on or after December 31, 2009, this SCO is now included in the Company’s crude oil and natural gas reserve totals.

“Proved” oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Under the Final Rule it is required that these reserves be evaluated using 12-month average prices and current costs and be disclosed net of royalties. The Company has also provided these reserves using forecast prices and costs in a sensitivity table as permitted by the SEC under the Final Rule.

“Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of required equipment is relatively minor to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Undeveloped” reserves are reserves of any category that 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 directly offsetting development spacing areas that are reasonably certain of production when drilled unless reliable technology exists that establishes reasonable certainty of economic producibilty at greater distances.

”Probable” reserves estimates are provided as optional disclosure under the Final Rule. Probable reserves are those additional reserves that are less certain to be recovered than proved, however, together with proved are as likely as not to be recovered. Under the Final Rule it is required that these be evaluated using 12-month average prices and current costs and be disclosed net of royalties. The reserve estimates could be materially different from the quantities ultimately realized. The Company has also provided these reserves using forecast prices and costs in a sensitivity table as permitted by the SEC under the Final Rule.

39	Canadian Natural Resources Limited

The 12-month average price and current cost case assumes that the 2009 average prices adjusted for quality and transportation, as well as the 2009 costs, are held constant over life. The 12-month average prices are determined by calculating the arithmetic unweighted average of the first-day-of-month price for each month of the 12-month period prior to December 31, 2009. These 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 2009 values shown below. In addition, operating and capital costs have not been increased on an inflationary basis. The following table outlines the prices calculated and used (based on a foreign exchange rate of US$0.87/C$1.00):

	Natural gas 12-month average price								Crude oil & NGLs 12-month average price
(Year)	Company average price (C$/mcf)		Henry Hub Louisiana (US$/mmbtu)		AECO (C$/mmbtu)		Huntingdon/ Sumas (C$/mmbtu)		Company average price (C$/bbl)		WTI @ Cushing(1) (US$/bbl)		WCS(2) (C$/bbl)		Edmonton Par(3) (C$/bbl)		North Sea Brent (US$/bbl)
2009		4.02		3.87		3.87		3.92		59.39		61.18		58.49		66.07		59.91

(1)	“WTI @ Cushing” refers to the price of West Texas Intermediate crude oil at Cushing, Oklahoma.

(2)	“WCS” refers to the price of Western Canada Select at Hardisty, Alberta.

(3)	“Edmonton Par” refers to the price of light gravity (40° API), low sulphur content crude oil at Edmonton, Alberta.

The forecast price and cost case assumes 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. Capital and operating costs are escalated at 2% per year. Future crude oil, NGLs and natural gas price forecasts were based on Sproule’s December 31, 2009 crude oil, NGLs and natural gas pricing model.

The Company’s weighted average crude oil and NGLs price and the weighted average natural gas price in the 2009 evaluation for 2010 were $75.92 per barrel and $5.48 per mcf respectively. The crude oil, NGLs and natural gas forecast prices used in the Evaluation Reports are as follows:

	Natural gas								Crude oil & NGLs
(Year)	Company average price (C$/mcf)		Henry Hub Louisiana (US$/mmbtu)		AECO (C$/mmbtu)		Huntingdon/ Sumas (C$/mmbtu)		Company average price (C$/bbl)		WTI @ Cushing (US$/bbl)		WCS (C$/bbl)		Edmonton Par (C$/bbl)		North Sea Brent (US$/bbl)
2010		5.48		5.70		5.36		5.61		75.92		79.17		74.14		84.25		77.92
2011		6.36		6.48		6.21		6.46		80.82		84.46		78.29		89.99		83.19
2012		6.60		6.70		6.44		6.69		82.83		86.89		76.86		92.61		85.59
2013		7.43		7.43		7.23		7.48		85.32		90.20		78.87		96.19		88.88
2014		8.20		8.12		7.98		8.23		87.11		92.01		79.49		98.13		90.65
2015		8.39		8.28		8.16		8.41		89.18		93.85		81.09		100.11		92.47
2016		8.53		8.45		8.34		8.59		90.73		95.72		82.73		102.13		94.32
2017		8.70		8.62		8.52		8.77		93.64		97.64		84.40		104.19		96.20
2018		8.87		8.79		8.71		8.96		95.97		99.59		86.10		106.30		98.13
2019		9.06		8.96		8.90		9.15		99.53		101.58		87.84		108.44		100.09
2020		9.26		9.14		9.10		9.35		101.42		103.61		89.61		110.63		102.09

Note: Foreign exchange rate used was US$0.92/C$1.00.

Canadian Natural Resources Limited

10.	The estimated total development capital costs, net to the Company, necessary to develop the reported reserves:

	Proved				Probable
(C$millions)	12-Month Average case		Forecast Price Case		12-Month Average case		Forecast Price Case
2010		2,003		2,033		298		292
2011		2,250		2,382		1,578		1,615
2012		1,868		2,028		2,616		2,735
2013		1,711		1,907		3,552		3,832
2014		1,173		1,331		3,155		3,419
2015		941		1,115		1,557		1,727
2016		1,023		1,200		1,369		1,551
2017		736		894		285		3,331
2018		564		704		309		346
2019		575		701		283		341
2020		533		655		273		376
Thereafter		2,207		30,694		20,500		23,422

11.	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 GLJ and Sproule to be reasonable.

A report on reserves data by the independent qualified reserves evaluators are provided in Schedule “A” to this Annual Information Form. A report by the Company’s management and directors on crude oil and natural gas disclosure is provided in Schedule “B” to this Annual Information Form. The Company does not file estimates of its total crude oil and natural gas reserves with any U. S. agency or federal authority other than the SEC.

41	Canadian Natural Resources Limited

C.	RECONCILIATION OF CHANGES IN NET RESERVES

The following table summarizes the changes during the past year in reserves after deduction of royalties payable to others and using 12-month average prices and costs for 2009 and year end prices and costs for 2008 and 2007.

Crude Oil and NGLs Reserves Reconciliation, Net of Royalties

	North America				International		Total
Net Proved Reserves (mmbbl)	Synthetic Crude Oil(1)	Bitumen	Crude Oil & NGLs	Total	North Sea	Offshore West Africa
Reserves, December 31, 2007(1)				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(1)	–	690	258	948	256	142	1,346
Extensions and discoveries	–	24	6	30	–	–	30
Improved recovery	–	8	75	83	–	–	83
SEC Reliable Technology (2)	–	7	–	7	–	–	7
SEC Rule Transition (3)	1,650	–	–	1,650	–	–	1,650
Purchases of reserves in place	–	–	1	1	–	–	1
Sales of reserves in place	–	–	–	–	–	–	–
Production	–	(49)	(24)	(73)	(14)	(11)	(98)
Economic revisions due to prices	–	(64)	(8)	(72)	57	(4)	(19)
Revisions of prior estimates	–	79	11	90	(59)	(4)	27
Reserves, December 31, 2009	1,650	695	319	2,664	240	123	3,027

Canadian Natural Resources Limited

	North America				International		Total
Net Probable Reserves (mmbbl)(4)	Synthetic Crude Oil (1)	Bitumen	Crude Oil & NGLs	Total	North Sea	Offshore West Africa
Reserves, December 31, 2007(1)				625	95	58	778
Extensions and discoveries				25	-	-	25
Improved recovery				15	(2)	(4)	9
Purchases of reserves in place				6	-	-	6
Sales of reserves in place				-	-	-	-
Production				-	-	-	-
Economic revisions due to prices				31	36	-	67
Revisions of prior estimates				(51)	14	(5)	(42)
Reserves, December 31, 2008(1)	-	548	103	651	143	49	843
Extensions and discoveries	-	11	5	16	-	-	16
Improved recovery	-	4	37	41	-	-	41
SEC Reliable Technology (2)	-	3	-	3	-	-	3
SEC Rule Transition (3)	862	-	-	862	-	-	862
Purchases of reserves in place	-	-	1	1	-	-	1
Sales of reserves in place	-	-	-	-	-	-	-
Production	-	-	-	-	-	-	-
Economic revisions due to prices	-	(71)	5	(66)	(44)	(2)	(112)
Revisions of prior estimates	-	23	(23)	-	48	9	57
Reserves, December 31, 2009	862	518	128	1,508	147	56	1,711

43	Canadian Natural Resources Limited

Natural Gas Reserves Reconciliation, Net of Royalties
Net Proved Reserves (bcf)	North America	North Sea	Offshore West Africa	Total
Reserves, December 31, 2007(1)	3,521	81	64	3,666
Extensions and discoveries	140	-	-	140
Improved recovery	52	(1)	6	57
Property purchases	77	-	-	77
Property disposals	(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(1)	3,523	67	94	3,684
Extensions and discoveries	92	-	-	92
Improved recovery	11	-	-	11
SEC Reliable Technology (2)	-	-	-	-
Property purchases	15	-	-	15
Property disposals	(6)	-	-	(6)
Production	(443)	(4)	(6)	(453)
Economic revisions due to prices	(335)	12	(4)	(327)
Revisions of prior estimates	170	(8)	1	163
Reserves, December 31, 2009	3,027	67	85	3,179

Canadian Natural Resources Limited

Net Probable Reserves (bcf)(4)	North America	North Sea	Offshore West Africa	Total
Reserves, December 31, 2007(1)	1,081	32	24	1,137
Extensions and discoveries	42	-	-	42
Improved recovery	14	(2)	(6)	6
Property purchases	16	-	-	16
Property disposals	(5)	-	-	(5)
Production	-	-	-	-
Economic revisions due to prices	(8)	(7)	2	(13)
Revisions of prior estimates	(44)	4	17	(23)
Reserves, December 31, 2008(1)	1,096	27	37	1,160
Extensions and discoveries	19	-	-	19
Improved recovery	2	-	-	2
SEC Reliable Technology (2)	-	-	-	-
Property purchases	4	-	-	4
Property disposals	(1)	-	-	(1)
Production	-	-	-	-
Economic revisions due to prices	(94)	(5)	(1)	(100)
Revisions of prior estimates	(61)	5	3	(53)
Reserves, December 31, 2009	965	27	39	1,031

1.	Reserves evaluated prior to December 31, 2009 were evaluated based on year end prices and costs. Previous year totals do not include SCO reserves.

SEC Reliable Technology accounts for reserves volumes added due to the reserves rule changes to allow booking of undeveloped reserves beyond one spacing unit with supporting geoscience and engineering data. Canadian Natural uses the combination of seismic, well logs, core analysis, production history and analogies to support the booking of undeveloped reserves.

SEC Rule Transition accounts for the inclusion of Horizon SCO reserves volume additions as a result of oil sands mining being included as a crude oil and natural gas activity effective December 31, 2009. For continuity purposes, with respect to the transition from Industry Guide 7 into the SEC’s Final Rule, the following table has been provided to illustrate the changes in the Company’s Horizon SCO reserves for the 2009 year.


Horizon SCO Reserves