Institutional Investor Open House December 5, 2018

Transcription

1 Institutional Investor Open House

2 Presenter Biographies: N. Murray Edwards Executive Chairman Mr. Edwards has been a Director of the Company since 1988, when he helped refinance the Company. He is a leading investor in and a Managing Director and Executive Chairman of Canadian Natural Resources Limited, Ensign Energy Services Inc. and Magellan Aerospace Corporation. After moving to Calgary in 1983, he became a lawyer and later a Partner with Burnet, Duckworth & Palmer, a Calgary based law firm. Mr. Edwards holds a Bachelor of Commerce degree from the University of Saskatchewan with Great Distinction and a Bachelor of Laws degree from the University of Toronto with Honours. Steve W. Laut Executive Vice-Chairman Mr. Laut was appointed to the positon of Executive Vice-Chairman of Canadian Natural Resources Limited in March 2018 after serving as President since Mr. Laut joined Canadian Natural in 1991 as a Senior Exploitation Engineer and was appointed to positions of increasing responsibility as Vice-President Operations in 1996 and Executive Vice-President Operations in After becoming Chief Operating Officer in 2003, assuming responsibility for all aspects of exploration, exploitation and production for Canadian Natural, he was appointed President and Chief Operating Officer in 2005 and became solely responsible for the President s role in Prior to joining Canadian Natural, Mr. Laut held various positions as Reservoir Engineer and Production Engineer with Poco Petroleum, Adams Pearson, Petro-Canada, Dome Petroleum and Unocal. Mr. Laut holds a Bachelor of Science degree in Mechanical Engineering from the University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geoscientists of Alberta (APEGA). Tim S. McKay President Mr. McKay joined Canadian Natural in 1990 as a Production Engineer and eventually was appointed Vice-President, Production, in He was named Senior Vice-President, Production in 2001 and to Senior Vice President, Operations in In 2010, Mr. McKay assumed the role of Chief Operating Officer, responsible for all aspects of exploration, exploitation and production in the Company. Mr. McKay joined Canadian Natural s Board of Directors effective February 27, 2018 and was appointed President of the Company effective March 1, Prior to joining the Company, Mr. McKay worked as a Production Engineer with EOG Canada. Mr. McKay holds a Bachelor of Science degree in Petroleum Engineering from the University of Alberta. Darren M. Fichter Chief Operating Officer, Exploration and Production Darren Fichter was appointed Chief Operating Officer, Exploration and Production of Canadian Natural in January 2018 after serving as Executive Vice-President, Canadian Conventional since Mr. Fichter joined Canadian Natural in 1996 as an exploitation and production engineer within the Canadian Conventional and International Divisions and he was appointed to Exploitation Manager in He was subsequently promoted in 2009 to Vice President, Exploitation International based in Aberdeen, Scotland. After returning to Canada in 2012 as Vice President, Exploitation, he was promoted to Senior Vice President, Exploitation in Mr. Fichter has 23 years of experience in the oil and gas industry and holds a Bachelor of Science degree in Mechanical Engineering from the University of Calgary. Scott G. Stauth Chief Operating Officer, Oil Sands Mr. Stauth joined Canadian Natural in In 2003 he was appointed Manager, Eastern Field Operations responsible for Thermal, Heavy Oil and Pelican. In 2006 Mr. Stauth assumed the position of Vice-President, Field Operations, responsible for Thermal and Conventional Field Operations in western Canada. In 2011 Mr. Stauth was appointed Senior Vice-President Operation Field, Facilities & Pipelines, responsible for Field Operations and Facility installations. In 2013 Mr. Stauth assumed the role of Senior Vice- President North American Operations, responsible for Thermal/Conventional Field Operations and working with Horizon Operations. In 2014 Mr. Stauth accepted the role of Senior Vice-President, North American Operations, now responsible for the Horizon, Thermal and Conventional Field Operations. In 2017 Mr. Stauth was appointed Executive Vice President, Canadian Field Operations adding the responsibility of Athabasca Oil Sands Project. In 2018 Mr. Stauth was appointed Chief Operating Officer, Oil Sands. Prior to joining the Company, Mr. Stauth worked as an Operations Superintendent with Koch Exploration Canada Ltd. He has 29 years of operations experience in oil and natural gas production. Corey B. Bieber Chief Financial Officer & Senior Vice-President, Finance Mr. Bieber has worked for Canadian Natural since 2001 when he joined the Company as Treasurer, also managing the Investor Relations program. Mr. Bieber was named Vice-President in 2005 and became a member of Canadian Natural s Management Committee in 2009 and was named Chief Financial Officer & Senior Vice-President Finance in March Prior to joining Canadian Natural, Mr. Bieber held various financial positions within Nexen and Enbridge. He has 30 years of experience in the oil and gas industry, with an emphasis on strategic financial analysis and disclosure. Mr. Bieber holds a Bachelor of Commerce degree and a Chartered Accountant Designation.

3 Presenter Biographies: Pamela A. McIntyre Senior Vice President, Safety, Risk Management & Innovation Mrs. McIntyre joined Canadian Natural in 2003 as Manager, Asset Integrity and in 2007, relocated to our U.K. office (Aberdeen) as Project Integration Manager. Upon Pamela s return to Canada in 2011, she was promoted to Vice President, Safety and Asset Integrity and in May 2018, Pamela was further promoted to Senior Vice President, Safety, Risk Management and Innovation. Mrs. McIntyre holds a Professional Engineering degree (University of Windsor) and before joining Canadian Natural, Mrs. McIntyre held a Research and Development position with a large steel company prior to moving into the upstream and midstream oil and gas industry in the position of Asset Integrity Engineer. Mrs. McIntyre is a board member of ABSA (Alberta Boilers Safety Association); is chair of Energy Safety Canada; and is co-chair of the Pipeline Safety Task Force. Bryan C. Bradley Vice-President, Marketing Mr. Bradley is currently the Vice President, Marketing with Canadian Natural Resources Limited, a large producer of crude oil and natural gas in the Western Canadian Sedimentary Basin, North Sea and offshore West Africa and the operator of the Horizon Oil Sands facility, with its main office in Calgary, Alberta. Mr. Bradley joined Canadian Natural in 2000 as a Crude Oil Trader, and was promoted to Manager of Downstream Assets in 2002, and subsequently promoted to Vice President, Marketing in Prior to joining Canadian Natural, Mr. Bradley held the position of a Process Engineer and Crude Oil Trader with Petro Canada. He has more than 30 years of experience in the oil and gas industry specializing in marketing of crude oil, natural gas, sulphur, NGL and petroleum coke. Mr. Bradley holds a Professional Engineering degree with an MBA from the University of Alberta. Mark A. Stainthorpe Vice-President, Finance Capital Markets Mr. Stainthorpe has worked for Canadian Natural for 15 years. Mr. Stainthorpe held various roles in Operations Accounting, Treasury, and Investor Relations before becoming Director, Treasury and Investor Relations in In 2018, Mr. Stainthorpe was appointed to his current position of Vice President, Finance Capital Markets. Mr. Stainthorpe holds a Bachelor of Commerce degree in Finance and a Bachelor of Arts degree in Psychology from the University of Calgary and a Chartered Financial Analyst designation.

4 INSTITUTIONAL INVESTOR OPEN HOUSE PREMIUM VALUE. DEFINED GROWTH. INDEPENDENT. Agenda Presentations Introduction Mark Stainthorpe Strategy & 2019 Budget Tim McKay Exploration & Production Darren Fichter Oil Sands Mining & Upgrading Scott Stauth Technology, Innovation & Continuous Improvement Pam McIntyre Marketing Bryan Bradley Finance Corey Bieber Summary Tim McKay Break Senior Management Q&A 2018 INVESTOR OPEN HOUSE 2 1

5 Forward Looking Statements Certain statements relating to Canadian Natural Resources Limited (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, proposed or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout the Company's Management s Discussion and Analysis ( MD&A ) of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands ("Horizon") operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Projects, the cost and timing of construction and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil ( SCO ) that the Company may be reliant upon to transport its products to market, development and deployment of technology and technological innovations and the assumption of operations at processing facilities 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 as 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 and proved plus probable crude oil, natural gas and natural gas liquids ( NGLs ) 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 and uncertainties 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 capital programs; the Company s and its subsidiaries ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of 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 and in mining, extracting or upgrading the Company s bitumen products; availability and cost of financing; the Company s and its subsidiaries success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs 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 expenditures and production expenses); asset retirement obligations; the adequacy of the Company s provision for taxes; and other circumstances affecting revenues and expenses. The Company s operations have been, and in the future may be, affected by political developments and by national, 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 factors is not exhaustive. Unpredictable or unknown factors not discussed in the Company's MD&A 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 applicable law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company s estimates or opinions change. Reporting Disclosures Special Note Regarding Currency, Production and Reserves In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data are presented on a before royalties basis unless otherwise stated. In addition, reference is made to crude oil, natural gas and NGLs in common units called barrel of oil equivalent ("BOE") or thousand cubic feet of gas equivalent ( McfGE ). A BOE is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil or NGLs (6Mcf:1bbl). An McfGE is derived by converting one barrel of crude oil or NGLs to six thousand cubic feet of natural gas (1bbl:6Mcf). These conversions may be misleading, particularly if used in isolation, since the 6Mcf:1bbl ratio or the 1bbl:6Mcf ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil or NGL prices relative to natural gas prices, the 6Mcf:1bbl or 1bbl:6Mcf conversion ratios may be misleading as an indication of value. This document, herein incorporated by reference, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board. For the year ended December 31, 2017 the Company retained Independent Qualified Reserves Evaluators ( IQREs ), Sproule Associates Limited and Sproule International Limited (together as Sproule ) and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved and proved plus probable reserves with an effective date of December 31, 2017 and a preparation date of February 7, Sproule evaluated the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves. GLJ evaluated the Horizon SCO reserves and reviewed the AOSP SCO reserves. The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) and disclosed in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ) requirements. Reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 Extractive Activities - Oil and Gas in the Company s Form 40-F filed with the SEC in the Supplementary Oil and Gas Information section of the Company s Annual Report. Special Note Regarding non-gaap Financial Measures The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the MD&A and the audited consolidated financial statements for the year ended December 31, All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ("IASB"). The Company's MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; adjusted cash production costs and adjusted depreciation, depletion and amortization. These financial measures are not defined by IFRS 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, cash flows from operating activities, and cash flows from investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-gaap measure adjusted net earnings from operations is reconciled to net earnings, as determined in accordance with IFRS, in the Financial Highlights section of the Company's MD&A. The non-gaap measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial Highlights" section of the Company's MD&A. The non-gaap measure net capital expenditures is reconciled to cash flows from investing activities, as determined in accordance with IFRS, in the Net capital expenditures section of the Company's MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the "Operating Highlights - Oil Sands Mining and Upgrading" section of the Company's MD&A. The Company also presents certain non-gaap financial ratios and their derivation in the Liquidity and Capital Resources section of the Company's MD&A. A Barrel of Oil Equivalent ( BOE ) is derived by converting six thousand cubic feet ( Mcf ) of natural gas to one barrel ( bbl ) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production volumes and per unit statistics are presented throughout the Company's MD&A on a before royalty or gross basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. Production on an after royalty or net basis is also presented for information purposes only. Adjusted net earnings from operations is a non-gaap measure that represents net earnings as presented in the Company's consolidated Statements of Earnings, adjusted for certain items of a non-operational nature. The Company considers adjusted net earnings from operations a key measure in evaluating the Company's performance. The reconciliation Adjusted Net Earnings from Operations presented in this MD&A, presents the after-tax effects of certain items of a non-operational nature that are included in the Company s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. Adjusted funds flow (previously referred to as funds flow from operations) is a non-gaap measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, and abandonment and other expenditures. The Company evaluates its performance based on adjusted funds flow. The Company considers adjusted funds flow a key measure as it demonstrates the Company s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities is presented below in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies. Net capital expenditures is a non-gaap measure that represents cash flows from investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other longterm assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company s capital spending activities in comparison to the Company's annual capital budget. The reconciliation Net Capital Expenditures, as Reconciled to Cash Flows from Investing Activities is presented in the Net Capital Expenditures section of this MD&A on page 25. Net capital expenditures may not be comparable to similar measures presented by other companies. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2017, is available on SEDAR at and on EDGAR at 2

6 Strategy Tim McKay, President Key Message Increasing Returns Optimal Cash Flow Allocation Robust Throughout Cycles Unique, Balanced Asset Base Proven Effective Strategy A UNIQUE EXPLORATION & PRODUCTION COMPANY 6 3

7 Canadian Natural A Unique E&P Company Built for All Cycles Long Life Low Decline asset base Low maintenance capital requirements Effective and efficient operations Flexible, disciplined free cash flow allocation Strong Balance Sheet, strengthening Liquids free cash flow breakeven of WTI ~US$39/bbl including dividends Disciplined & Delivering Real Value to Shareholders CFPS, EPS, Production per share growth Increasing ROCE, ROE, Dividend Yield Increasing returns to shareholders through dividends and share purchases Optionality to deliver significant long-term value growth with market access Massive low cost resource to develop Low price periods have minimal impact on corporate asset value ROBUST THROUGH THE CYCLES 7 Canadian Natural Strategy Flexible capital allocation to maximize value Strong Balance Sheet supports investment grade credit ratings Defined growth / value enhancement plans by product and basin Large, diverse, balanced asset base Product mix Project timelines Drill bit and acquisitions Opportunistic acquisitions Effective and efficient operations Area knowledge Extensive infrastructure ownership Operatorship of core areas Environmentally and socially responsible operations PROVEN EFFECTIVE STRATEGY 8 4

8 Balanced, Diverse Portfolio North America North Sea Offshore Africa Natural Gas ~24% Heavy Crude Oil ~23% Balanced, diverse production mix International exposure Vast, balanced resource base to develop Growing, sustainable adjusted funds flow >50% light crude oil and SCO production 2019 Base Budget BOE Production Mix Liquids Production Mix Oil Sands Mining & Upgrading (SCO) ~40% Long Life Low Decline ~74% Light Crude Oil & NGLs ~13% Low Capital Exposure ~26% BUILDING A WORLD CLASS COMPANY 9 Canadian Natural s Competitive Advantages Balanced portfolio of assets Diverse product inventory and time horizons Owned and controlled infrastructure Long Life Low Decline assets Low maintenance capital requirements Size drives economies of scale Strategic Facilitates capital flexibility to maximize returns Expertise in all areas, leverage technology Nimble, able to capture opportunities Access to capital markets Cultural advantages Delivering Free Cash Flow ROBUST SUSTAINABLE FREE CASH FLOW 10 5

9 Canadian Natural s Advantage Impact of Long Life Low Decline Assets on Corporate Decline Rate BOE Production Mix Maintenance Capital of ~$3.1 billion required Pelican & Thermal ~12% Decline Oil Sands Mining & Upgrading ~0% Decline Long Life Low Decline Production ~57% ~10% Corporate Decline Rate Conventional Assets ~19% Decline Low Capital Exposure Production ~43% Note: Conventional Assets include North America crude oil and NGLs, International crude oil and natural gas. LOW DECLINE RATE 11 Long Life Low Decline Asset Profile Price Impact on Production & Value Production from Long Life Low Decline assets withstands price volatility Minimal impact on NPV No impact on corporate declines Commodity Price Production Rate Time Long Life Low Decline Production Commodity Price LONG LIFE LOW DECLINE PRODUCTION SUPPORTS BUSINESS 12 6

10 Low Capital Exposure Asset Profile Price Impact on Production & Value Production* Timing has major impact on project NPV Significant declining production Operating costs increase with lower production Commodity Price Production Rate Time *Single well production profile. Value Creation Value Destruction Commodity Price TIMING CAN ERODE ECONOMIC VALUE 13 Balanced Model Price Impact on Production & Value Low capital exposure production grows Long life assets provide sustainable production and low declines Exercising capital flexibility by reducing spend on low capital exposure assets Balance Sheet remains strong through the cycle Ability to ramp up production faster with improving prices Stronger Balance Sheet Low Capital Exposure Production Commodity Price Production Rate Time Long Life Low Decline Production Commodity Price BALANCED MODEL DELIVERS BEST OF BOTH WORLDS 14 7

11 Balanced Model Production per Share Basis Price Impact on Production & Value Production per share grows at a higher rate Assets deliver free cash flow in low price environment Free cash flow allocation policy results in share purchases Production per share continues to grow Production per share grows at a higher rate Low Capital Exposure Production Production per Share Rate Commodity Price Long Life Low Decline Production Commodity Price Time DELIVERS FREE CASH FLOW THROUGH THE CYCLE 15 1P Reserves After Royalties 2017 (MMBOE) 8,000 7,000 6,000 5,000 4,000 CNQ 3,000 2,000 1,000 0 CNQ SU CVE OXY EOG DVN NBL CHK IMO APC HSE APA ECA Peers Integrated Peers Peers include: APA, APC, CVE, CHK, DVN, ECA, EOG, HSE, IMO, NBL, OXY, SU. Source: 2017 Net Proved reserves, constant dollar, per corporate reports. SIGNIFICANT VALUE TO UNLOCK 16 8

12 Industry Leading 1P FD&A Costs ( ) 3 Year Average ($US/BOE, net) $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 CNQ Peer Average Peers Integrated Peers Peers include APC, CHK, CPG, COP, CVE, DVN, ECA, EOG, HSE, IMO, NBL, OXY, SU. Source: BMO 2018 Oil & Gas Global Cost Study. Represents 3 year average ( ). Note: Excludes change in FDC costs and includes revisions. TOP TIER FD&A COSTS 17 Recycle Ratio ( ) 3 Year Average (x) CNQ Peer Average 0.0 CVE HSE CNQ NBL SU CPG IMO EOG OXY ECA CHK APC DVN COP Peers Integrated Peers Peers include APC, CHK, CPG, COP, CVE, DVN, ECA, EOG, HSE, IMO, NBL, OXY, SU. Source: BMO 2018 Oil & Gas Global Cost Study. Represents 3 year average ( ). TOP TIER RECYCLE RATIO 18 9

13 Production per Share ( ) 5 Year CAGR Production/Share (% CAGR) 8% 7.0% 6% 4% 2% CNQ 0% -2% CNQ -4% -6% Peers Integrated Peers (9.3%) (9.8%) (9.8%) (14.9%) Peers include: APA, APC, CHK, COP, CVE, DVN, ECA, EOG, HSE, IMO, MRO, NBL, OXY and SU. Note: Production net of royalties. Source: BMO 2018 Oil & Gas Global Cost Study and company reports. Represents 5 year CAGR ( ). TOP TIER PRODUCTION PER SHARE GROWTH 19 Return on Capital Employed ( ) 5 Year Average (%) 8% 6% 4% 2% 0% -2% -4% -6% 8.0% CNQ 2018F * 4.4% CNQ * -8% Peers Integrated Peers (11.6%) (18.9%) (20.2%) * included on average ~$2 billion per year of project capital which did not earn a return ( ~$900 million and 2018F - ~$230 million). Peers include: APA, APC, CHK, COP, CVE, DVN, ECA, EOG, HSE, NBL, OXY, SU, TOU. Source: BMO 2018 Oil & Gas Global Cost Study and company reports. Represents 5 year average ( ). CNQ 2018F from company reports. TOP TIER RETURN ON CAPITAL 20 10

14 Canadian Natural Delivers on Four Pillars of Capital Allocation Maximizing Shareholder Value Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions FLEXIBLE CAPITAL ALLOCATION MAXIMIZES SHAREHOLDER VALUE Delivered on Expectations 11

15 Track Record of Delivering on the Four Pillars From 2017 Open House Resource Development Disciplined corporate capital ~$4.0 to $4.5 billion Will be prudent to not create cost inflation Opportunistic Acquisitions No gaps in portfolio Must add value Balance Sheet Strength Will get larger portion near term Balance Sheet strengthens quickly Returns to Shareholders Growing, sustainable dividends Opportunistic share purchases Bias towards dividends DISCIPLINED ALLOCATION, FOCUSED ON VALUE CREATION 23 Track Record of Delivering on the Four Pillars 2018 Execution Resource Development Remained disciplined with $4.2 billion (1) in capital expenditures Focus on effective and efficient operations ~12% production growth Opportunistic Acquisitions Strategic low cost acquisitions adding significant long-term value Joslyn and Laricina have a combined bitumen in place potential of ~6.2 billion barrels OBIP (2), providing long-term strategic value Significant synergies resulting in over $500 million in cost savings Note: Numbers quoted above are based on 2018F guidance. (1) Excludes net acquisition capital. (2) Original Bitumen in Place, 14:1 TV:BIP for Joslyn and >10 meters of high quality, clean pay for Grand Rapids (Laricina). DISCIPLINED BALANCE OF CAPITAL ALLOCATION 24 12

16 Track Record of Delivering on the Four Pillars 2018 Execution Balance Sheet Strength Debt to book capitalization improved from 41% to 37% Debt to adjusted EBITDA improved from 2.7x to 1.7x Net debt reduction of $2.8 billion (1) Available liquidity of $5.3 billion (2) Moody s credit rating upgraded to Baa2 Transparent free cash flow allocation policy (1) Includes the impact of foreign exchange, working capital and other adjustments. (2) Includes cash and cash equivalents. Note: Numbers quoted above are YTD September 30, 2018 compared to December 31, See Advisory for definitions. DISCIPLINED BALANCE OF CAPITAL ALLOCATION 25 Track Record of Delivering on the Four Pillars 2018 Execution Returns to Shareholders 18 th consecutive year of dividend increases Increased quarterly dividend by 22% Purchased ~29.6 million shares for an aggregate total of $1.2 billion * Over $2.8 billion returned to shareholders via dividends and share purchases * Transparent free cash flow allocation policy *January 1, 2018 to November 30, DISCIPLINED BALANCE OF CAPITAL ALLOCATION 26 13

17 Free Cash Flow Allocation 2018 Year to Date Ending Q3/18 Adjusted Funds Flow Less: Capital Expenditures Less: Dividends $7.9 billion $3.2 billion $1.2 billion Free Cash Flow $3.5 billion Share purchases of ~$1.2 billion year to date Nov 30, 2018 Balance Sheet Strength ~$2.6 billion Share Purchases ~$875 million Note: See Advisory for definitions. Capital expenditures exclude net acquisitions. BALANCED FREE CASH FLOW ALLOCATION 27 Free Cash Flow Allocation Policy Annual Adjusted Funds Flow Less: Budgeted Capital Expenditures Less: Dividends Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions 50% Free Cash Flow 50% Balance Sheet Strength Share Purchases Targets = 1.5x Debt/EBITDA and $15.0 billion in Absolute Debt Note: Policy is effective November 1, 2018 and targeted to be in place until at least the Company s Normal Course Issuer Bid renewal in May Policy to be reviewed quarterly by the Board of Directors. Please see Advisory for definitions. SUPPORTED BY STRONG BALANCE SHEET & SUSTAINABLE FREE CASH FLOW 28 14

18 2019 Plan Balancing the Four Pillars 2019 Plan Balance Sheet Strength Balance Sheet strengthens through free cash flow allocation policy Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Returns to Shareholders Growing, sustainable dividends Share purchases through free cash flow allocation policy Economic Resource Development Disciplined corporate capital allocation Will be prudent to not create cost inflation Opportunistic Acquisitions No gaps in portfolio Must add value DISCIPLINED ALLOCATION, FOCUSED ON VALUE CREATION 30 15

19 2019 Budget Strategy Align capital spend and production growth with takeaway capacity in short-term Incremental takeaway capacity of ~615,000 bbl/d through 2019 Disciplined capital allocation 2019 base capital budget slightly above maintenance capital $3.7 billion Curtail volumes in short-term Align production with higher netback pricing Continued focus on effective and efficient operations Free cash flow allocation policy DISCIPLINED VALUE CREATING STRATEGY Execution Priorities Optimize assets Oil Sands Mining & Upgrading capture synergies Pelican Lake optimize field Primrose pad adds targeting first oil in Q4/19 Execute on Kirby North targeting first oil in Q4/19 Enhance capital flexibility $1,460 million Low Capital Exposure Assets $2,240 million Long Life Low Decline Assets Enhance execution Improve effectiveness and efficiency SAFE, SUSTAINABLE EFFECTIVE & EFFICIENT OPERATIONS 32 16

20 2019 Capital Budget ($ million) 2018 Guidance 2019 Base Budget 2019 Normalized Budget North America Natural Gas & NGLs $440 $365 $365 North America Crude Oil 1, ,055 International Crude Oil Total Exploration & Production $1,965 $1,600 $1,880 Thermal In Situ Oil Sands $960 $545 $745 Oil Sands Mining & Upgrading Strategic, project development, environment & technology $465 $505 $705 Sustaining Capital Turnarounds, Reclamation & Other Total Oil Sands Mining & Upgrading $1,290 $1,525 $1,725 Net Acquisitions, Midstream & Other Total $4,605 $3,700 $4,380 CAPITAL DISCIPLINE Budget Drilling Program 2018F * 2019 Base Budget 2019 Normalized Budget Natural Gas Wells Crude Oil Wells Heavy Oil Thermal Pelican Light International Total *Net producer wells. Well counts are rounded. DISCIPLINED DRILLING PROGRAM 34 17

21 2019 Base Budget Production Targeted Production 2018F 2019B % Change (1) Natural Gas (MMcf/d) 1,545-1,555 1,485-1,545 (2%) Crude Oil & NGLs (Mbbl/d) North America (4%) North America Thermal In Situ % North America Oil Sands Mining & Upgrading (2) % International % Total Crude Oil & NGLs Total MBOE/d 1,070-1,081 1,030-1,119 - Total MBOE/d Exit Rate (3) 1,095-1,106 1,085-1,174 3% (1) Percent change of 2019B base budget midpoint over 2018F midpoint. (2) Reflects planned downtime for turnaround activities and Canadian Natural s 70% ownership in the AOSP. (3) Percent change of December 2018F midpoint exit rate compared to December 2019B base budget midpoint exit rate. Note: Rounded to the nearest 1,000 bbl/d. Numbers may not add due to rounding. 3% EXIT GROWTH RATE WITH ONLY 97 NEW WELLS Base Budget Capital Breakdown Maintenance Capital ($ million) (1) 2019B Exploration & Production (2)(3) $1,490 Thermal In Situ Oil Sands 375 Oil Sands Mining & Upgrading 950 Abandonment & Reclamation 265 Total Maintenance Capital $3,080 Growth Capital Exploration & Production (3) $75 Thermal In Situ Oil Sands 40 Oil Sands Mining & Upgrading 505 Total Growth Capital $620 Total Capital $3,700 Maintains Production Volumes Post 2019 Production On Stream (1) Maintenance capital to maintain current production mix. (2) Includes Midstream and other. (3) Includes North America E&P and International E&P. LOW MAINTENANCE CAPITAL TO KEEP PRODUCTION FLAT 36 18

22 Canadian Natural 2019 Targeted Free Cash Flow Scenarios: Impacts of Volatility ($ billion) $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 Free Cash Flow ~$2.9B (before dividends) Strip as at Dec 3, 2018 Free Cash Flow ~$3.1B (before dividends) Curtailment & Market Access Clarity Free Cash Flow ~$4.6B (before dividends) Strip as at Oct 19, Capital ($ billion) $3.7 $4.4 $4.7 Capital Free Cash Flow Note: Free cash flow represents adjusted funds flow less capital. See Advisory for cautionary statements, definitions and pricing assumptions. SUSTAINABLE FREE CASH FLOW Value Adding Options Growth Projects $MM Value Oil Sands Mining* $200 Horizon Stages 1B/2 Horizon Paraffinic Froth On-stream date not delayed one year Increase reliability and lowers operating costs Restart execution, adds 40,000 bbl/d - 50,000 bbl/d in 2024 Low cost barrels Thermal* $200 Primrose Kirby Conventional $280 Wembley Pierson Pelican Lake Primary Heavy Crude Oil Total $680 Adds ~12,000 bbl/d in 2020 and ~20,000 bbl/d in 2021 Lowers operating costs Adds ~15,000 bbl/d in 2020 with a ~4,300 bbl/d 2019 exit rate *2019 normalized capital only; reflects portion of multi-year capital program. DEPENDENT ON PRICE STABILIZATION & MARKET ACCESS CLARITY 38 19

23 5 Year Production per Share Growth (Production/Share) Capital ($ billion) 2018F 2019B 2020F 2021F 2022F Strip pricing $4.6 $3.7 $4.7 $4.7 $4.5 *Based upon midpoint to midpoint for indicated year range. Note: See Advisory for pricing assumptions, cautionary statements and definitions. SIGNIFICANT PRODUCTION PER SHARE GROWTH 39 Key Message Increasing Returns Optimal Cash Flow Allocation Robust Throughout Cycles Unique, Balanced Asset Base Proven Effective Strategy A UNIQUE EXPLORATION & PRODUCTION COMPANY 40 20

24 Exploration & Production Assets Darren Fichter, Chief Operating Officer, Exploration and Production Economic Resource Development Exploration & Production Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Economic Resource Development Large, diverse and balanced asset base Owned and controlled infrastructure Exposure to proven and emerging plays Highly flexible capital Free cash flow generation FLEXIBLE CAPITAL ALLOCATION MAXIMIZES SHAREHOLDER VALUE 42 21

25 Natural Gas, Light Crude Oil & NGLs Strategy Maximize value through disciplined area approach Proactive, disciplined, flexible development Continue focus on liquids rich natural gas and light crude oil assets Maximize value through owned infrastructure; extensive drill to fill inventory Leverage technology, innovation and continuous improvement to: Increase production Increase recoveries Lower costs Maintain our top-tier land base Maximize operating free cash flow* generation ~$270 million 2018F *See Advisory for cautionary statements and definitions. MAXIMIZING VALUE THROUGH DISCIPLINE 43 Natural Gas, Light Crude Oil & NGLs Core Area Summary BC CNQ Land Base AB SK MB Largest natural gas producer in Canada Q3/18 ~1,489 MMcf/d 9.5 Tcf 2P reserves* Significant light crude oil and NGL production base Q3/18 ~93,000 bbl/d light oil & NGLs 574 million barrels 2P reserves* High quality light crude oil horizontal multi-frac opportunities ~200 active water floods Maximize recovery Shallow decline *Company Gross proved plus probable reserves at December 31, TOP TIER ASSET BASE 44 22

26 Natural Gas, Light Crude Oil & NGLs Montney Umbach West Nig Graham Stoddart Septimus Septimus Minor Greater Wembley Elmworth Gold Creek Kakwa BC Lean Gas (<10 bbl/mmcf) Liquids Rich Gas ( bbl/mmcf) Light Oil AB Large inventory of defined development projects Many large contiguous land holdings ~1.0 million net acres Key liquids rich / light crude oil properties Greater Wembley Area Wembley, Albright, Knopcik, Gordondale Septimus Gold Creek / Elmworth Smoky Wild River SIGNIFICANT PREMIUM GROWTH POTENTIAL 45 Natural Gas, Light Crude Oil & NGLs Infrastructure Advantage Deep Basin / Montney Umbach West Nig Graham Stoddart Septimus Septimus Minor Gordondale Greater Wembley Elmworth Gold Creek Extensive owned and controlled infrastructure Facilitates low capital exposure drill to fill strategy Strategic infrastructure proximal to liquids rich land base ~2.2 Bcf/d net design capacity ~1.3 Bcf/d net available capacity CNQ Land Base CNQ Sour Facilities CNQ Sweet Facilities BC AB Smoky Wild River INFRASTRUCTURE ADVANTAGE SIGNIFICANTLY IMPROVES ECONOMICS 46 23

27 Natural Gas, Light Crude Oil & NGLs Greater Wembley Area Progress Gas Plant CNQ Land Base Existing Montney wells Gas Plants Pipelines Large, concentrated liquids rich Montney land Facilitates efficient area program ~155 net sections of undeveloped land de-risked by proven production Sexsmith Gas Plant Wembley Gas Plant Strategic owned infrastructure in place Owned plant capacity of 186 MMcf/d ~365 net locations identified Targeting ~510 bbl/d liquids and ~3MMcf/d natural gas per well* in the greater Wembley area *Assumes US$60/bbl WTI, C$1.50/GJ AECO and US$1.00 to C$1.25 foreign exchange and IP90. Note: See Advisory for cautionary statements. EXTENSIVE LIQUIDS RICH MONTNEY LANDS 47 Natural Gas, Light Crude Oil & NGLs Wembley Project CNQ Land Base Existing Montney wells Targeted Drilling Gas Plants Pipelines Sexsmith Gas Plant Wembley Gas Plant 18 Montney crude oil wells drilled to date 213 potential net locations on 88 net sections Targeting ~530 bbl/d liquids and ~2 MMcf/d natural gas per well* Leveraging technology & area expertise to lower costs Applying monobore drilling Pad development Water management Development plan Leverage owned infrastructure & processing capacity 36 wells targeted *Assumes US$60/bbl WTI, C$1.50/GJ AECO and US$1.00 to C$1.25 foreign exchange and IP90. Note: See Advisory for cautionary statements. CONCENTRATED LANDS DRIVE EFFICIENCIES 48 24

28 Natural Gas, Light Crude Oil & NGLs Wembley Project Drilling Performance (C$ 000 s) $4,000 $3,500 Monobore drilling Pad developments Concentrated land $3,000 $2,500 $2, F Drill Cost Per Well Source: Company reports. DRIVING DRILLING COSTS LOWER 49 North America Light Crude Oil & NGLs Rich Gas Septimus Montney Area Success Story Liquids rich, drill to fill, natural gas development Septimus Gas Plant Gas Reinjection Pilot Tower Tower Oil Battery CNQ Land Base 100% owned ~160 MMcf/d gas plant Leveraging infrastructure to maximize value from the Tower light crude oil play Septimus Top tier operating costs YTD 2018 $0.32/Mcfe MAXIMIZING NETBACKS 50 25

29 Technology Development Septimus Natural Gas Reinjection Pilot Production Time F 2019F 2020F 2021F 1.3x-1.7x Enhanced Liquids Recovery Primary Liquids Recovery 1.0x Source: Society of Petroleum Engineers paper SPE MS presented March 13, Gas cycling/storage targets two objectives Increased liquids recovery Store produced gas during low price periods Pilot targeted for Septimus in 2019 Opportunities throughout liquids rich land base Leveraging strategically owned and operated facilities Unlocks liquids rich development in a constrained natural gas takeaway environment MAXIMIZING RESOURCE VALUE THROUGH TECHNOLOGY 51 Natural Gas, Light Crude Oil & NGLs Summary Large inventory of defined development projects Liquids rich natural gas and light crude oil Montney opportunities Extensive owned and strategically located infrastructure Leveraging technology and area knowledge to increase recoveries and lower costs WTI (US$/bbl) $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 >200,000 bbl/d at or below US$50 WTI 25,000 50,000 75, , , , , ,000 Production Capability (bbl/d)* *Reflects Light crude oil and C5+ potential volumes additions. Note: Assumes C$1.50/GJ AECO and US$1.00 to C$1.25 foreign exchange. See Advisory for cautionary statements. DISCIPLINED APPROACH MAXIMIZING VALUE 52 26

30 Heavy Crude Oil Strategy Maximize value through: Proactive, disciplined, flexible development Optimizing and expansion of Pelican Lake polymer flood Leveraging technology, innovation and continuous improvement to: Increase production Increase recoveries Lower costs Continued focus on cost control Leveraging vast high quality land base and owned infrastructure Large drilling inventory Drives economies of scale Maximize operating free cash flow* generation ~ $455 million 2018F *See Advisory for cautionary statements and definitions. DISCIPLINE & TECHNOLOGY MAXIMIZE VALUE 53 Heavy Crude Oil Core Area Summary Cliffdale Smith CNQ Land Base CNQ Heavy Crude Oil Producing Properties ~500 km Pelican Lake AB SK Bonnyville & Lloydminster area Largest Primary heavy crude oil producer in Canada Q3/18 production of ~92,000 bbl/d Industry leading polymer flood at Pelican Lake Q3/18 production of ~63,000 bbl/d 2P reserves 741 million barrels* Large inventory of development opportunities Controlled pace of development Premium land base and extensive infrastructure Effective and efficient operator *Company Gross proved plus probable reserves as at December 31, VAST LAND BASE & OWNED INFRASTRUCTURE MAXIMIZES VALUE 54 27

31 Heavy Crude Oil Primary Heavy Crude Oil AB SK CNQ Land Base CNQ Heavy Crude Oil Producing Properties CNQ ECHO Pipeline Disciplined area approach Extensive land base with deep inventory of repeatable programs Commitment to environmental stewardship, with proven track record of reducing GHG emissions 71% reduction in absolute methane vent volumes ~200 km HIGHLY REPEATABLE, FLEXIBLE PROJECTS 55 Heavy Crude Oil Pelican Lake Industry leading Enhanced Oil Recovery (EOR) technology Long Life Low Decline assets Industry leading heavy crude oil recovery Primary recovery 6% Wabiskaw Pool Boundary Water flood after primary 15% Polymer after water flood 22% Polymer after primary 28% CNQ Land Base CNQ Polymer Flood Heavy Oil Processing Facilities 2P reserves of 469 million barrels* ~20 year reserve life *Company Gross proved plus probable reserves as at December 31, INDUSTRY LEADING EOR TECHNOLOGY 56 28

32 Pelican Lake Operating Costs ($/bbl) $11.00 $10.00 $9.00 $8.00 $7.00 $6.00 Leveraging area and technological expertise Economies of scale Facility consolidation on target for April 2019 ~$6 million/year in operating cost savings Targeting additional savings from: Bulk polymer purchases Consolidation of power contracts Elimination of underutilized camps $ Source: Company reports. Q3/18 OPERATING COSTS OF $6.43/bbl 57 Heavy Crude Oil Technological Advancement Horizontal multilateral opportunities Extensive land base provides exposure to many emerging plays Smith AB SK 2 examples Smith, AB Golden Lake, SK Potential for ~150 horizontal multilateral wells CNQ Heavy Crude Oil Producing Properties CNQ Land Base Golden Lake ~500 km LEVERAGING TECHNOLOGICAL LEARNINGS 58 29

33 Heavy Crude Oil Horizontal Multilateral Technology Smith, Alberta Leveraging technology and area knowledge 6 horizontal multilateral wells drilled in 2018 Initial rates exceeded expectations by >50% at ~325 bbl/d per well CNQ Land Base Potential Multilaterals Existing Wells Drilled Clearwater pool boundary ~19 net sections in sweet spot of pool Follow up potential for ~118 additional horizontal multilateral wells Assessing future potential Water flood Polymer flood TECHNOLOGY & LEARNINGS LEVERAGED INTO NEW POOLS 59 Heavy Crude Oil Horizontal Multilateral Technology Golden Lake, SK Vintage vertical wells Pool average rates <15 bbl/d per well Leveraging technology and area knowledge 3 horizontal multilateral wells drilled in 2018 Initial rates of ~115 bbl/d per well Follow-up potential for ~35 additional horizontal multilateral wells CNQ Land Base Potential Multilaterals 2018 Multilateral wells Vintage Vertical & Single Leg wells TECHNOLOGY & LEARNINGS CREATE OPPORTUNITIES 60 30

34 Heavy Crude Oil Horizontal Multilateral Opportunities Extensive land base provides exposure to many potential plays 11 additional area based development opportunities have been identified Smith AB SK Potential of ~575 locations Capability of ~70,000 bbl/d* ~125 bbl/d per well CNQ Land Base CNQ Heavy Crude Oil Producing Properties Potential Multilateral Horizontal Opportunities ~500 km Golden Lake Leveraging technology facilitated by large, concentrated land base *Assumes US$60/bbl WTI, C$1.50/GJ AECO and US$1.00 to C$1.25 foreign exchange and IP90. Note: See Advisory for cautionary statements. SIGNIFICANT OPPORTUNITIES TO CREATE ADDITIONAL VALUE 61 Heavy Crude Oil Summary Pelican Lake Long Life Low Decline 2P reserves 469 million barrels (1) ~20 year reserve life Industry leading EOR technology and expertise unlocks reserves and value Polymer recovery factor of 22-28% Effective and efficient operations Q3/18 operating costs of $6.43/bbl Primary heavy crude oil Low Capital Exposure Disciplined project execution to match commodity price cycle Extensive land base with deep inventory of repeatable programs Capability to add over ~200,000 bbl/d at US$50/bbl WTI (2) Technology advancement will unlock value on large land base (1) Company Gross proved plus probable reserves as at December 31, (2) Assumes C$1.50/GJ AECO and US$1.00 to C$1.25 foreign exchange and IP90. Note: See Advisory for cautionary statements. DISCIPLINED APPROACH MAXIMIZING VALUE 62 31

35 International Operations Strategy Maximize value through: Leveraging offshore expertise in Aberdeen Capturing low risk development opportunities Effective and efficient operations Maximize operating free cash flow* generation ~$520 million 2018F Capture new opportunities within existing portfolio Participate in South Africa Big E exploration *See Advisory for cautionary statements and definitions. GEOGRAPHICAL BALANCE PROVIDES CAPITAL FLEXIBILITY 63 International Light Crude Oil Summary Q3/18 light crude oil production ~47,000 bbl/d 2P reserves 305 million barrels * North Sea Low decline Low risk development opportunities Côte d Ivoire High return, low risk development opportunities Exploration upside South Africa Exploration upside North Sea Côte d Ivoire South Africa *Company Gross proved plus probable reserves as at December 31, SIGNIFICANT FREE CASH FLOW GENERATION 64 32

36 International Light Crude Oil North Sea 2019 platform drilling program 6.7 net well program 3.9 net producer wells Follow-up of 2018 drilling success ~28,700 bbl/d in Q3/ levels Effective and efficient operations Top tier drilling performance ~17% increase from Reduced operating costs per barrel ~41% since 2015 Industry leading abandonment and decommissioning results MAXIMIZING FREE CASH FLOW GENERATION THROUGH EFFICIENCIES 65 International Light Crude Oil Côte d Ivoire Baobab Extended Phase 4 development Exit 2018 production targeted to exceed original plan of 5,370 bbl/d* First two wells producing at ~5,700 bbl/d* Third well on stream November 27, 2018 Kossipo 2019 appraisal well (58% working interest) Pool development potential of ~20,000 bbl/d (gross) Espoir Commence Phase 4 development in 2019 *All production and well counts are on a net working interest basis. HIGH RETURN ON CAPITAL OPPORTUNITIES 66 33

37 International Light Crude Oil South Africa Exploration Drilling 5 structures identified with up to ~1.0 billion barrels OOIP per structure 25% working interest Upfront cash consideration and financial carry Future bonus payments on commercial discovery Brulpadda 1AX exploration well re-entry Targeted drilling window Q4/18 - Q1/19 Brulpadda 1AX well location LOW CAPITAL EXPOSURE TO BIG E EXPLORATION 67 Economic Resource Development Exploration & Production Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Economic Resource Development Large, diverse and balanced asset base Owned and controlled infrastructure Exposure to proven and emerging plays Highly flexible capital Free cash flow generation FLEXIBLE CAPITAL ALLOCATION MAXIMIZES SHAREHOLDER VALUE 68 34

38 Oil Sands Scott Stauth, Chief Operating Officer, Oil Sands Economic Resource Development Oil Sands Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Economic Resource Development Long Life Low Decline assets Massive resource in place Maximize value through continuous improvement Leveraging technology Sustainable and robust free cash flow generation DELIVERS SUSTAINABLE FREE CASH FLOW 70 35

39 Thermal In Situ Oil Sands Thermal In Situ Oil Sands Strategy Maximize value through strategic timing of development Align with improved market access Leverage infrastructure Land consolidation at Primrose, Pelican Lake and Kirby Utilize and optimize technology, innovation and continuous improvement Focus on capital, operating cost and Steam to Oil Ratio ( SOR ) reductions Leverage expertise to maximize value from all horizons McMurray Grand Rapids Clearwater Grosmont Bluesky Capture near-term development opportunities Maximize operating free cash flow* generation ~$335 million in 2018F *See Advisory for cautionary statements and definitions. DISCIPLINED DEVELOPMENT 72 36

40 Thermal In Situ Oil Sands Portfolio CNQ Thermal Producing Properties CNQ In Situ Project Inventory Peers Germain Pelican Peace River Liege Saleski Birch Mtn. Grouse Lindbergh Ells River Gregoire Leismer Kirby Ipiatik Primrose Wolf Lake Marie Lake Long Life Low Decline assets Facility capacity of ~220,000 bbl/d (1) Q3/18 production volumes of ~112,000 bbl/d 2P reserves 2.58 billion barrels (2) Majority working interest and operatorship Effective and efficient thermal operator Leverage use of technology to enhance recovery and optimize costs Expertise in Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD) and Steam flood (1) Includes Kirby South, Kirby North, Primrose and Wolf Lake facility capacities. (2) Company Gross proved plus probable reserves as at December 31, VAST LAND BASE & GREAT ASSETS = FLEXIBILITY 73 Thermal In Situ Oil Sands Portfolio CNQ Thermal Producing Properties CNQ In Situ Project Inventory Peers Birch Mtn. Ells River Clearwater Producing Germain Liege Saleski Gregoire McMurray Producing Pelican Leismer Bluesky Producing Peace River Grouse Lindbergh Kirby Ipiatik Primrose Grand Rapids Producing Grosmont Future Potential Wolf Lake Marie Lake LEVERAGE EXPERTISE TO UNLOCK RESERVES 74 37

41 Thermal In Situ Oil Sands Portfolio Potential Clearwater McMurray Bluesky Grand Rapids Grosmont ~5.4 billion barrels OBIP* Currently producing at Primrose and Wolf Lake ~32.0 billion barrels OBIP* Currently producing at Kirby South ~17.5 billion barrels OBIP* Currently producing at Peace River ~2.8 billion barrels OBIP* Currently producing at Wolf Lake ~44.0 billion barrels OBIP* Significant future potential *Original Bitumen in Place >10 meters of high quality, clean pay. SIGNIFICANT FUTURE POTENTIAL 75 Thermal In Situ Oil Sands Primrose / Wolf Lake Primrose North Steam Generation Facility Primrose South Steam Generation Facility Primrose East Steam Generation Facility Wolf Lake Central Oil Processing and Steam Generation Facility Overlapping Clearwater, Grand Rapids and McMurray developments Higher netback pricing Decades of highly economic pad additions High rate and recovery in early life of CSS Decades of Long Life Low Decline, low capital Steam flood production Follow-up process to CSS Targeted recovery factor increase of ~20% over CSS SOR continues to improve ~14% reduction year over year* Potential for Solvent enhancements Potential for ~50% reduction in SOR *2017 to 2018 decrease in SOR for areas under Steam flood only. VAST INVENTORY CREATES VALUE 76 38

42 Primrose & Wolf Lake Development Opportunities 2018 pad add program drilling 63 wells Wolf Lake Primrose North Primrose South Primrose East Primrose 1,158 CSS wells 22 SAGD well pairs Wolf Lake 278 CSS wells 273 SAGD well pairs Acquired Lands Primrose North 231 CSS wells Pad Locations Undrilled Development Pads Targeted first oil production in Q4/19 Targeted first 12 month production of ~26,000 bbl/d Significant development opportunities (50+ years) Maximize utilization of existing facilities Potential for phased expansions totaling ~80,000 bbl/d Wolf Lake facilities Primrose East facilities LARGE PORTFOLIO OF DEVELOPMENT OPPORTUNITIES 77 Thermal In Situ Oil Sands Kirby South SAGD Kirby Southwest Approved Project Area Approved Development Area Drilled Development Pads Kirby Southwest Future Pads Ipiatik Future Pads Ipiatik Kirby South Strong Q3/18 performance Production of ~36,000 bbl/d and SOR of 2.8 Operating costs <$10/bbl Future plans Significant reserve life (~16 years) Maximize value from consolidated land base Kirby Southwest Phase 1 development Targeted 29 well pairs Targeting first oil in Q1/21 Ipiatik development Consolidated 44 net sections offsetting lands Seismic and stratigraphic drilling plans in place to optimize the development plan ADDING VALUE WITH LONG LIFE LOW DECLINE SAGD ASSETS 78 39

43 Thermal In Situ Oil Sands Kirby North SAGD Kirby North Overall project 84% complete and ahead of schedule Drilling is ~85% complete Technology added VITs and ICDs* Commissioning of facility targeted for Q3/19 Targeted first oil in Q4/19 Targeted capacity of ~40,000 bbl/d Capacity targeted for early 2021 Approved Project Area Approved Development Area Drilled Development Pads Future Pads Decades of potential to maintain capacity *Vacuum Insulated Tubing and Inflow Control Device. OPTIMIZED DEVELOPMENT STRATEGY DRIVES ECONOMICS 79 Thermal In Situ Oil Sands Summary Large and diverse asset base with significant potential Long Life Low Decline assets Total of billion barrels OBIP (1) Leverage technical expertise to unlock reserves Leverage infrastructure Highly economic pad add programs utilizes capacity Significant capacity of ~220,000 bbl/d (2) ~112,000 bbl/d currently utilized Leverage technology, innovation and continuous improvement Pace development strategically with market access (1) Original Bitumen in Place >10 meters of high quality, clean pay. (2) Includes Kirby South, Kirby North, Primrose and Wolf Lake facility capacities. MAXIMIZING VALUE 80 40

44 Oil Sands Mining & Upgrading Oil Sands Mining & Upgrading Strategy Leverage technology, innovation and continuous improvement Reduce operating costs Increase reliability Optimize production and recovery Reduce environmental footprint Continue to improve safety performance Progress future opportunities to increase economic production and reserves Advance engineering and design specification 75,000 bb/d to 95,000 bbl/d Horizon potential for phased expansion opportunities ~260,000 bbl/d of SCO AOSP potential Jackpine mine has regulatory approval for expansion ~100,000 bbl/d Align opportunities with market access Maximize operating free cash flow* generation ~$5.5 billion in 2018F *See Advisory for cautionary statements and definitions. DISCIPLINED DEVELOPMENT 82 41

45 Oil Sands Mining & Upgrading Advantages CNQ Operating Oil Sands Mines CNQ Lands ~72 km CNQ Horizon Oil Sands Joslyn CNQ AOSP Q3/18 production volumes of ~394,000 bbl/d Total of ~17.5 billion barrels OBIP (1) 2P reserves 6.06 billion barrels (2) Significant resource in place 50+ year life (3) No decline, reservoir risk or reserve replacement cost Significant economies of scale Operating synergies 2 sites Top tier operating costs, reliability and utilization Leverage technology, innovation and continuous improvement Fort McMurray (1) Original Bitumen in Place, 14:1 TV:BIP. (2) Company Gross proved plus probable reserves as at December 31, (3) Including future pit development. LONG LIFE NO DECLINE ASSETS 83 Oil Sands Mining & Upgrading Synergy Updates Implementation of Canadian Natural s Continuous Improvement initiatives at the Albian mine operations Utilized synergies and the sharing of best practices On-going implementation of synchronized maintenance strategy between sites Optimized Fly-in, Fly-out program Leveraging buying power Optimization of service provider utilization between sites SYNERGIES MAXIMIZE VALUE FOR SHAREHOLDERS 84 42

46 Oil Sands Mining & Upgrading Canadian Natural s Continuous Improvement Pathway Top Tier Performance Time Phase 2 & 3 staged project expansion execution Implementation of Canadian Natural s Continuous Improvement initiatives, including production and efficiency projects drives operating cost reductions Reduction of ~38% in operating costs in 3 years* Acquisition of Albian mines (70%) Implementation of best practices and optimizations at Albian, increases production and reduces costs Over 2,300 employees trained in continuous improvement workshops *Based upon Oil Sands Mining and Upgrading operating costs per barrel of SCO adjusted for planned downtime. INCREMENTAL GAINS = VALUE CREATION 85 Oil Sands Mining & Upgrading Plant Capacity Utilization 100% 90% 80% 70% 60% 12 month 24 month CNQ Peer Average Note: Sourced from TD research, Mine your own Business, dated November 6, Peers Include: IMO, SU, and Syncrude. CONTINUOUS IMPROVEMENT DRIVES HIGH SUSTAINABLE UTILIZATION 86 43

47 Oil Sands Mining & Upgrading Operating Costs (C$) $45.00 Equivalent to ~$3.3 billion in additional margin in 2018 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $ F* Cash Costs Fuel Costs *2018 based upon YTD actuals. Operating expenses reflect production downtime for turnarounds (unadjusted). Source: Company reports. CONTINUOUS IMPROVEMENT DRIVES SIGNIFICANT REDUCTIONS 87 Oil Sands Mining & Upgrading Operating Costs Peer Compare (C$/bbl) $55.00 $50.00 $45.00 $40.00 $35.00 $30.00 $25.00 $20.00 $15.00 $ F* CNQ Peer Average *CNQ 2018F based upon midpoint of 2018 operating expense corporate guidance. Peers 2018F is average of first three quarter actuals. Operating expenses include energy costs and reflect production downtime for turnarounds (unadjusted). Source: Company reports. Peers include AOSP ( owned by Shell), SU and Syncrude. INDUSTRY LEADING OPERATING COSTS 88 44

48 Horizon Oil Sands Joslyn Lease Plan Significant value realized from savings and efficiencies from optimizing the mine plan Estimated cost savings of over $500 million Allows the extension of current Horizon South pit operations to new lease Defers North Pit relocation costs Adds significant value Additional ~3.2 billion barrels of gross OBIP* Potential location of In Pit Extraction Process (IPEP) implementation Additional savings if implemented *Original Bitumen in Place, 14:1 TV:BIP. MAXIMIZE VALUE THROUGH SYNERGIES 89 Horizon Oil Sands Paraffinic Froth Treatment Expansion Incremental production target of 40,000-50,000 bbl/d of diluted bitumen Project utilizes excess capacity in extraction and OPP to produce diluted bitumen Utilize excess naphtha in SCO to dilute and transport product Potential for lean froth currently being tested in extraction Engineering and design specification work underway Favorable preliminary capital efficiencies Targeted total capital required of ~$1.4 billion Sanction targeted in late 2019 Depending on market access HIGH QUALITY ECONOMIC PRODUCTION GROWTH 90 45

49 Horizon Oil Sands Reliability Opportunities Reliability opportunities provide incremental economic production Incremental 35,000 bbl/d - 45,000 bbl/d of SCO Stage 1B reliability improvements on Diluent Recovery Unit and install swing tanks Improves long term reliability Stage 2A optimize design and increase reliability Increase capacity in pumping equipment and improve metallurgy Stage 2B increase Horizon calendar day SCO production Increasing capacity in hydrotreaters and Diluent Recovery Unit Additional Sulphur Recovery Unit Stage 2C increase stream day capacity Increased capacity of the wet gas compressor Associated capacity increase in all utilities IMPROVED RELIABILITY & VALUE ENHANCEMENT 91 Oil Sands Mining & Upgrading Autonomous Trucks Longer term opportunity compared to peers due to current top tier haul truck utilization Current haul truck utilization ~90% Jackpine Mine 18 truck operation pilot Capital cost of ~$75 million Implementation Plan at Jackpine Mine 3 truck trial at targeted for late truck overburden operation targeted for early autonomous trucks targeted for 2022 Long-term potential of running all 140+ trucks at all 3 mines Incremental capital cost is targeted to be $275 million to $325 million Reduced operating costs of ~$0.30/bbl - $0.50/bbl Staged implementation to all mines targeted for 2022 to 2025 COST IMPROVEMENTS THROUGH INNOVATION 92 46

50 Oil Sands Mining & Upgrading In Pit Extraction Process (IPEP) Potential for cost savings of $2.00/bbl - $3.00/bbl for operating and sustaining costs ~40% less GHG emissions during bitumen production Eliminates tailings ponds Overburden mining shovel to conveyor reducing haul truck fleet Extraction technology that separates bitumen in the mine pit Pilot test started in April 2018 Relocatable, modular extraction plant Moves as mine face advances Produces stackable dry tailings Accelerates reclamation plant IPEP Field Pilot at Horizon ADVANCING TAILINGS MANAGEMENT TECHNOLOGIES 93 Horizon Oil Sands Long Term Opportunities Horizon Phase 4 & 5 Increase capacity by ~260,000 bbl/d of SCO Executed in a step wise and disciplined manner Significant potential, contingent on market access Pierre River Integration opportunities with Horizon ~1.8 billion barrels of gross OBIP* Potential of ~250,000 bbl/d of SCO, contingent on market access AOSP Jackpine Mine expansion Regulatory approval for a ~100,000 bbl/d expansion, contingent on market access *Original Bitumen in Place, 14:1 TV:BIP, 70% working interest. VALUE DRIVEN LONG TERM POTENTIAL TO ADD ~610,000 BBL/D 94 47

51 Economic Resource Development Oil Sands Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Economic Resource Development Long Life Low Decline assets Massive resource in place Maximize value through continuous improvement Leveraging technology Sustainable and robust free cash flow generation DELIVERS SUSTAINABLE FREE CASH FLOW 95 48

52 Sustainable Operations Through Technology, Innovation & Continuous Improvement Pam McIntyre, Senior Vice-President, Safety, Risk Management and Innovation Technology, Innovation & Continuous Improvement Strategy Invest in research and development Leverage technology and innovation Canadian Natural s continuous improvement culture drives long-term value Socially responsible and proactive community involvement Deliver responsible and sustainable operations DELIVERING REDUCED ENVIRONMENTAL FOOTPRINT & LOWER COSTS 98 49

53 Technology, Innovation & Continuous Improvement Leading R&D investor ~$3.1 billion invested since 2009 Benefits Unlocking reserves Becoming more effective and efficient Increasing production Reducing environmental footprint Canadian Natural s culture of leveraging technology, innovation and continuous improvement is everyone s accountability and is key to driving sustainable operations and long-term value TECHNOLOGY, INNOVATION & CONTINUOUS IMPROVEMENT = SUSTAINABILITY 99 Structured Research & Development Funnel Discovery Design Develop Deploy Implemented Projects Capital Employed DISCIPLINED VALUE FOCUSED R&D

54 Technology & Innovation Technology & Innovation Why is it important? Basis for entrepreneurial culture Enhances sustainability Improves efficiencies Adds significant shareholder value today and in the future Creating value Lowers costs Enhances productivity Unlocks reserves and value Reduces environmental footprint DRIVING A CULTURE OF TECHNOLOGY & INNOVATION

55 Carbon Capture & Sequestration / Storage Technology 3 rd largest CO 2 capturer and sequesterer for oil and gas sector in the world (1) Reduced CO 2 footprint Reduced CO 2 charges Horizon Quest Horizon Quest (2) NWR (3) Tonnes per Year 0.4 million 1.1 million 1.2 million 2.7 million Equivalent to ~576,000 cars off the road per year (1) Per the Global CCS Institute. (2) Canadian Natural is a 70% working interest owner in Quest. (3) On stream in STRONG ENVIRONMENTAL INITIATIVES 103 Environmental Technology Water & Land Initiatives CO 2 sequestration technology and innovation at Horizon have helped reduce water usage ~80% of water from tailings ponds can be recycled more rapidly, as sequestration causes fine tailings to settle much quicker Annual fresh water withdrawals have been 1/3 of our regulated allocation since start-up in 2009 Horizon s tailings pond is approximately half the size than originally targeted In Pit Extraction Process (IPEP) separates bitumen in the mine pit Pilot to produce dry tails and eliminate tailings ponds Reduces water use Accelerates reclamation REDUCING OUR ENVIRONMENTAL FOOTPRINT

56 Thermal In Situ Oil Sands Technology Unlock Reserves & Reduce Emissions Vacuum Insulated Tubing (VIT) and Annulus Gas Blankets SAGD and PAW Steam flood Reduced heat loss = more energy available to heat bitumen and less GHG emissions per barrel of bitumen Less steam required to reduce bitumen viscosity reduces water use Non-Condensable Gas (NCG) Injection Pilot Kirby Co-injecting trace amounts of NCG, like methane, with steam into an oil sands reservoir Frees up steam capacity for use into lower SOR wells Solvent Enhanced SAGD Pilot Kirby and Primrose Demonstrate existing SAGD process can be improved by co-injecting solvent with steam Simulation studies and competitor pilot analysis show ~50% lower SOR less GHG emissions Primrose North Kirby Well Pads INCREASED RESERVES FOR LESS COST 105 Canadian Natural s Continuous Improvement Process 53

57 Canadian Natural s Continuous Improvement Why is it important? Canadian Natural s culture of continuous improvement is a competitive advantage Drives top tier performance in safe, reliable, effective and efficient operations Learnings are deployed across the Company s vast asset base Creating value Reduces environmental footprint Lowers costs Motivates people to adapt and share continuous improvement initiatives across the Company Maximizes shareholder value DRIVING OUR COMPETITIVE ADVANTAGE 107 Continuous Improvement Initiatives Procurement & Materials Management Centralized Warehouse (Transactions) 150, , ,000 90,000 70,000 50,000 30,000 10, (Cost/Transactions) $5.00 Average Annual Transactions Average Annual Cost Per Transaction $4.00 $3.00 $2.00 $1.00 $0.00 Increased productivity driven by LEAN/Kaizen activities and safety improvement programs Doubled volume of transactions Reduced transaction costs by ~35% Leveraging purchasing power Procurement best practices Increased visibility, identifying and tracking of spend Vendor and spend consolidation Leveraging inventory data Establishing data management standards Accelerating cycle time Intersection of item and spend strategies EFFECTIVE & EFFICIENT = COST SAVINGS

58 Continuous Improvement in GHG Emissions Primary Heavy Crude Oil Vent (e 3 m 3 /year) 200, , ,000 80,000 71% Reduction Absolute Vent Volumes Continuous improvement initiatives have reduced environmental emissions Heavy Oil Casing Gas vent reduction Solution Gas Conservation has reduced GHG emissions Total reduction of over 17.9 million CO 2 e tonnes over the last 5 years, equivalent to ~3.8 million cars off the road 40, STRENGTHENING ENVIRONMENTAL INITIATIVES 109 Continuous Improvement in GHG Emissions Horizon Oil Sands (tonnes CO 2 e/boe) % Reduction CONTINUING TO REDUCE ENVIRONMENTAL FOOTPRINT

59 Environmental Continuous Improvement Water Initiatives 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% Primrose and Wolf LakeThermal Operations (Percent Water Use) Non-Saline Water Saline Water Recycled Produced Water 0% Priority to maximize recycle and reuse of produced water Current average non-saline water usage near historic low Environmental benefits In 2017, over 80% of total water use came from recycled produced water ~75% decrease in non-saline water use from 2008 to 2017 Economic benefits Steam generation using recycled water lowers GHG emissions and fuel usage due to higher temperature of recycled produced water INCREASING RECYCLED PRODUCED WATER VOLUMES 111 Environmental Continuous Improvement Reclamation Initiatives (Certificates) (Hectares) 2,500 6,000 2,000 5,000 4,000 1,500 3,000 1,000 2, , Cumulative Certificates Cumulative Area (Wells) 1, % Reduction in Costs Total Wells Cost Per Well (Cost/Well) $150,000 $100,000 $50,000 $0 Over 5,300 hectares of land has been reclaimed in our North American E&P Operations Over 2,700 wells have been abandoned in the last 5 years Well abandonment costs down ~72% Technology paper issued to industry PROACTIVELY REDUCING OUR ENVIRONMENTAL FOOTPRINT

60 Delivering Responsible & Sustainable Operations Responsible & Sustainable Operations Why is it important? Communities benefit in our area operations Safety culture drives top tier performance and community acceptance Focus on environmental improvements Creating value Lower costs Reduced environmental footprint Engages the community to work together and add long-term mutual value WORKING TOGETHER TO MAXIMIZE VALUE

61 Culture of Working Together Community Engagement ($ million) $400 $350 $300 $250 $200 $150 $100 $50 $0 Contracts to Indigenous Business & Services Working together to create mutual value 75 Indigenous communities 35,000 land owners Focus on creating long term business and employment opportunities for Canada s Indigenous peoples Continued investment in training and development Industry collaboration on reducing environmental footprint COLLABORATION CREATES VALUE 115 Delivering Safe, Effective & Efficient Operations Safety is a Core Value Effective & Efficient 1.0 $ $ Total recordable injury frequency (per 200,000 hours) $ Operating Costs ($/BOE) Note: Total corporate operating costs per BOE. DELIVERING RESPONSIBLE LOW COST OPERATIONS

62 Environmental Excellence Corporate GHG Emissions Intensity (tonnes CO 2 e/boe) ~25% Overall Reduction Proactive environmentally responsible operations Reducing corporate greenhouse gas emissions intensity ~25% reduction over last 6 years Meet or exceed all regulatory requirements Continuous improvement initiatives have reduced emissions DELIVERING ENVIRONMENTALLY RESPONSIBLE OPERATIONS 117 An Example of the Power of Integrating Technology, Innovation & Canadian Natural s Continuous Improvement Processes 59

63 Oil Sands Well-to-Combustion GHG Emissions Intensity (kgco 2 e/bbl) Realized Success US Refined Average US Wyoming WC Saudi Arabia Ghawar Russia Samatlor Libya Waha CNQ Oil Sands Pathway Anglo Kutto Norway Oseberg CNQ Oil Sands 2017 Brazil Frade Iran Marun US Alaska Venezuala Indonesi Oil Sands North Slope Hamaca SCO Duri FCC & HC ~2009 Note: Total emissions intensity includes: production and upgrading, transportation, refining, transportation of refined product and combustion. CNQ Oil Sands includes: Oil Sands Mining and Upgrading and Thermal Crude Oil. Source: Internal company reports and ARC Energy Research Institute 2017 Report. CLEAR DEFINED GOAL TO REDUCE GHG EMISSIONS 119 Capturing Technological Improvements in Oil Sands Oil Sands Operations Pathway to the Future GHG Emissions Intensity (kgco 2 e/bbl) Current Technology Execution Future Technology Execution Future Technology Development US Refined Average Future State Aspirational Note: Total emissions intensity includes: production and upgrading, transportation, refining, transportation of refined product and combustion. CNQ Oil Sands operations includes: Oil Sands Mining and Upgrading and Thermal Crude Oil. Source: Internal company reports and ARC Energy Research Institute 2017 Report. PATHWAY TO CONTINUE TO REDUCE GHG EMISSIONS

64 Technology, Innovation & Continuous Improvement Leading R&D investor ~$3.1 billion invested since 2009 Benefits Unlocking reserves Becoming more effective and efficient Increasing production Reducing environmental footprint Canadian Natural s culture of leveraging technology, innovation and continuous improvement is everyone s accountability and is key to driving sustainable operations and long-term value TECHNOLOGY, INNOVATION & CONTINUOUS IMPROVEMENT = SUSTAINABILITY

65 Marketing Bryan Bradley, Vice-President, Marketing Marketing Natural gas WCSB production constrained by takeaway capacity Production base shifting to liquids rich natural gas and associated gas from crude oil Increased natural gas export pipeline access in 2021 and LNG in Potential technology change positively impacts natural gas development WCSB natural gas demand growing Crude oil and NGLs Temporary market access restrictions Market access improves through 2019; restrictions removed by Q4/19 TMX and KXL pipelines provide incremental export capacity SUPPORTING GROWTH PLAN

66 Natural Gas Markets Natural Gas Marketing Strategy Diversified natural gas sales portfolio maximizes value Support natural gas export construction and expansion Support infrastructure to manage liquids rich developments Evaluate alternative supply options within Alberta SUPPORTING GROWTH PLAN

67 Canadian Natural Balanced Portfolio of Natural Gas Sales 2018F* EXPORT MMcf/d AECO Sales 30% Canadian Natural Consumption 36% Dawn/Ontario 160 Empress 190 Emerson (Minnesota) 100 California 15 International 4% Exports 30% *Based upon midpoint of 2018F corporate natural gas production guidance of 1,550 MMcf/d. DIVERSIFIED PORTFOLIO MINIMIZES MARKET RISK 127 Crude Oil Markets 64

68 Crude Oil Marketing Strategy Manage crude oil market dynamics through temporary production curtailments and storage Support improved nomination processes and procedures Maximize netbacks through optimized blending and transportation options Committed to long-term export pipelines to diversify sales points Line 3 PADD II KXL US Gulf Coast TMX Global Markets Crude-by-rail Other Support projects that add heavy crude oil and bitumen conversion capacity Northwest Refinery ~80,000 bbl/d SUPPORTING GROWTH PLAN 129 Crude Oil Markets Update Short and medium-term outlook Supply exceeds pipeline/rail takeaway and storage nearing capacity Western Canadian heavy crude and light crude oil differentials challenged Mitigation of wider differentials Curtailment legislation by Government of Alberta Production declines and shut ins will reduce supply Increased rail capacity through short and long-term contracts Apportionment rules revised and enforced to reduce air barrels Differentials targeted to improve with incremental pipeline capacity Enbridge Line 3 (370,000 bbl/d) Increased mainline capacity (Q4/19) KXL (830,000 bbl/d) Canadian Natural 175,000 bbl/d committed (2021) Kinder Morgan (590,000 bbl/d) Canadian Natural 75,000 bbl/d committed (2022) IMO 2020 LONG-TERM PIPELINES SUPPORT GROWTH PLAN

69 Crude Oil Diversified Product Mix Liquids Production* Increased light crude and synthetic crude oil production Heavy Crude Oil 30% Synthetic Crude Oil 53% Increased active water flooding and leveraging technology in light crude oil drilling Increased capital allocation to liquids rich drilling away from dry natural gas Completion of the Horizon phase 3 expansion and AOSP acquisition in 2017 Light Crude Oil & NGL s 17% *Based upon midpoint of 2019B base capital budget corporate liquids production guidance. GREATER LIGHT CRUDE OIL MIX 131 Canadian Natural s Near-Term Differential Strategy Actively engaged Government of Alberta to evaluate options to bring supply and takeaway into balance Lead industry in revising nomination procedures to prevent parties from exploiting the system Producers require fair and equitable treatment to export production Evaluate and commit to opportunities to export crude-by-rail Optimize production to maximize value and minimized sale of distressed barrels November and December 2018 target of 45,000 bbl/d to 55,000 bbl/d of heavy crude oil production curtailments and additional light crude oil where appropriate CURTAILING PRODUCTION

70 Crude Oil Outlook by Q4/19 Effective takeaway capacity increases NWR Refinery ~50 Mbbl/d ~80 Mbbl/d increase heavy; ~30 Mbbl/d decrease light Incremental rail* ~150 Mbbl/d Throughout 2019 Conventional declines ~30-60 Mbbl/d May be higher Enbridge Line 3 on stream ~370 Mbbl/d Q4/19 Total ~615 Mbbl/d *September rail volumes equal approximately 270,000 bbl/d. DIFFERENTIALS IMPROVE THROUGH Constrained WCSB Takeaway Capacity to Markets (Mbbl/d) 7,000 6,000 Production > Pipe/Rail Capacity Rail TMX (590 Mbbl/d) 2018 CAPP Production Forecast 5,000 4,000 KXL (830 Mbbl/d) TMPL (300 Mbbl/d) Keystone (590 Mbbl/d) 3,000 2,000 Line 3 Expansion Q4/19 Enbridge Ex-Edmonton (2,728 Mbbl/d) 1,000 PADD IV (483 Mbbl/d) WC Refineries (672 Mbbl/d) SUPPLY/TAKEAWAY IMBALANCE

71 WCS Pricing & Enbridge Pipeline Apportionment (US$/bbl) $5.00 Actual Forecast Apportionment (%) 0% -$5.00 -$15.00 Keystone Outage Line 3 In-Service 5% 10% 15% 20% -$ % -$ $ $55.00 WCS (Canadian Natural Forecast) (LHS) WCS Strip pricing as at Novermber 23, 2018 (LHS) Enbridge Heavy Oil Apportionment (RHS) 30% 35% 40% 45% 50% Note: Persistent downstream pipeline apportionment resulted in downward pressure on WCS pricing in 2018.System constraints also result in increasing Canadian crude storage volumes. BIG SWINGS IN APPORTIONMENT 135 SCO Pricing & Enbridge Pipeline Apportionment (US$/bbl) Apportionment (%) Actual Forecast $5.00 0% $0.00 5% 10% -$5.00 -$ $ % 20% SCO (Canadian Natural Forecast) (LHS) Line 3 In-Service 25% SCO Strip Pricing as at 30% -$20.00 November 23, 2018 (LHS) 35% -$ $30.00 Enbridge Light Oil Apportionment (RHS) 40% 45% 50% Note: Significant storage build hit a critical point in Q3/18 resulting in all Canadian crude streams trading at a much wider differential. BIG SWINGS IN APPORTIONMENT

72 Crude Oil Index Pricing 2018 WCS Index (US$/bbl) Heavy Crude Oil Enbridge Heavy Apportionment Synthetic Crude Oil Synthetic Index (US$/bbl) Enbridge Light Apportionment January -$ % -$ % February -$ % -$ % March -$ % -$0.96 9% April -$ % $3.27 0% May -$ % -$ % June -$ % -$ % July -$ % -$ % August -$ % -$ % September -$ % $ % October -$ % -$ % November -$ % -$ % Note: WCS and SCO indexes are the price differences to WTI. WCS priced at Hardisty and SCO is priced at Edmonton. APPORTIONMENT NOT ALIGNED WITH INDEX PRICING 137 This Slide Screen Only

73 WCSB Condensate Supply Forecast (Mbbl/d) WCSB YOY condensate supply growth of ~30,000 bbl/d Import volumes will be used to balance the WCSB condensate system Potential for ~200,000 bbl/d of WSCB supply growth without impacting prices Production Import Domestic demand Source: CERI, CAPP. INCREMENTAL CONDENSATE WILL NOT REQUIRE TAKEAWAY 139 Canadian Crude Oil Exports by Rail (bbl/d) 300, , , , ,000 50,000 Source: National Energy Board, dated November 21, CRUDE-BY-RAIL PROGRESSIVELY INCREASING

74 Enbridge Line 3 Replacement Wabasca Heavy Albian Heavy Cold Lake Western Canadian Select NEB approval in July 2017 Enbridge Line Mbbl/d added export capacity from Alberta to PADD II Minnesota PUC approved Certificate of Need and Routing in June 2018 (with conditions) Superior, WI Markets: (5,100 Mbbl/d) Upper mid-west (460) PADD II (3,500) Eastern Canada (830) Cushing (via Flanagan, Spearhead = 340) Enbridge / Fond du Lac Band reach route agreement August 2018 Current cost estimate is C$5.3 billion / US$2.9 billion construction underway in Canada, US construction expected to begin at the end of Q1/19 TARGETED IN SERVICE DATE NOVEMBER Trans Canada Keystone XL Pipeline (KXL) Hardisty Terminal(s) Western Canadian Select Wabasca Heavy Albian Heavy Syn Cold Lake Blend Keystone XL Pipeline 830 Mbbl/d added export capacity Canadian Natural firm capacity of 175 Mbbl/d USGC Houston & Port Arthur 9.0 MMbbl/d total refining 4.0 MMbbl/d heavy refining Decision from the Nebraska Supreme Court expected in Q1/19 TransCanada remains committed to the project TARGETED IN SERVICE DATE

75 Trans Mountain Expansion Project (TMEP) Edmonton Terminal 7,800 Mbbl tank capacity Horizon Synthetic Cold Lake Blend Wabasca Heavy Albian Heavy Synthetic Trans Mountain Expansion Pipeline 590 Mbbl/d added export capacity Canadian Natural firm capacity of 75 Mbbl/d August 30, 2018 the Federal Court of Appeal required further review of: 1. The environmental effects of project-related marine shipping West Ridge Marine Terminal 7,500 Mbbl tank capacity Tidewater Markets Refining: Washington State (600 Mbbl/d) California (2.1 MMbbl/d) Asia (9 MMbbl/d) 2. Phase III consultation with Indigenous applicants The NEB has until February 22, 2019 to update its marine report; Canada has appointed former Supreme Court of Canada Justice Frank Iacobacci to oversee the indigenous consultation process TARGETED IN SERVICE DATE IMO 2020 Impact Light crude oil premiums offset heavy crude oil discounts Canadian Natural production mix <25% heavy crude oil versus >50% light crude oil and SCO on a BOE basis SCO production has a high diesel cut Net positive impact to Canadian Natural within all expected ranges BENEFIT OF A DIVERSIFIED PRODUCTION MIX

76 Canadian Natural Natural Gas & Crude Oil Marketing Diversified sales portfolio maximizes value Support infrastructure to manage liquids rich developments Intra-Alberta natural gas pipeline expansions facilitate increased exports Crude oil supply vs takeaway imbalance will be resolved through 2019 Committed to long-term export pipelines to diversify sales points SUPPORTING GROWTH PLAN

77 Finance Corey Bieber, Chief Financial Officer & Senior Vice-President, Finance Finance Strategy Balance Sheet strength while maximizing financial flexibility Balance Sheet targets of 1.5x debt to adjusted EBITDA and $15.0 billion in absolute debt Ample liquidity from diversified sources Flexible and disciplined capital programs Strong free cash flow generation Manageable maturity schedule Ensure strong investment grade credit ratings Access to capital markets Transparent free cash flow allocation policy on debt repayment Returns to shareholders 18 consecutive years of dividend increases 21% CAGR since inception Transparent free cash flow allocation policy on share purchase strategy Note: See advisory for definitions. DELIVERING ON OUR FINANCIAL PLAN

78 Balance Sheet Strength Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Balance Sheet Strength Balance Sheet is strong today Financial capability to manage through market conditions Access to capital markets Defined free cash flow allocation policy FLEXIBLE CAPITAL ALLOCATION MAXIMIZES SHAREHOLDER VALUE 149 Robust Financial Position Long-Term Ratings Outlook Short-Term Ratings DBRS BBB High Stable n/a Standard & Poor s BBB+ Stable A-2 Moody s Baa2 Stable P-2 Strong financial position as of September 30, 2018 Debt to book capitalization 36.8% Debt to adjusted EBITDA 1.7x Available liquidity of $5.3 billion* Moody s upgraded long-term debt rating to Baa2 September 13 th, 2018 *Includes cash and cash equivalents. Note: See advisory for definitions. DELIVERING ON OUR FINANCIAL PLAN

79 2017 Ending Debt Per Net BOE Reserves (US$/BOE) $12.00 $10.00 $8.00 $6.00 $4.00 Peer Average $2.00 $0.00 CNQ 2018F CNQ Peers Integrated Peers Peers include: APA, APC, CHK, COP, CVE, DVN, ECA, EOG, HSE, IMO, NBL, OXY, SU. Note: Sourced from company reports. 2018F uses forecasted 2018 ending debt over 2017 net reserves. See advisory for definitions. DEBT LEVELS SUPPORTED BY STRONG RESERVES 151 Balanced Credit Facility Profile Revolving Credit Facilities (1) (C$ million) Fully Drawn Term Credit Facilities (1) (C$ million) June 2021 (2) $2,425 June 2022 $2,425 Operating demand loan $100 North Sea operating line ( 15 million) $25 May 2020 $1,800 October 2020 $2,200 February 2021 $750 Total $4,750 Total $4,975 Lenders 18 banks diversified by location 15+ year relationships with 10 banks Note: As at September 30, (1) Financial covenant is based on consolidated debt to book capital ratio to not to exceed 0.65:1.00. (2) $2,095 million matures in June 2021, $330 million matures in June LARGE & DIVERSE BANKING GROUP SUPPORTS STRONG LIQUIDITY

80 Strategic Public Debt Maturity Profile (C$ billion) C$ Public US$ Public Note: Represents principal repayments only and does not reflect fair value adjustments, original issue discounts or transaction costs. Reflects foreign exchange rate of US$1.00 to C$1.31 as at October 31, OPTIONALITY THROUGH A BALANCED MATURITY PROFILE 153 Balanced Yet Flexible Funds Flow Allocation Targeted 9 Month 2018 Allocation* Actual 9 Month 2018 Allocation 15% 26% 33% 52% 31% 43% Balance Sheet Returns to Shareholders Resource Development & Acquisitions *Targeted 9 month 2018 allocation as announced in November DISCIPLINED CAPITAL ALLOCATION REMAINS FOCUS

81 Free Cash Flow Allocation 2018 Year to Date Ending Q3/18 Adjusted Funds Flow Less: Capital Expenditures Less: Dividends $7.9 billion $3.2 billion $1.2 billion Free Cash Flow $3.5 billion Share purchases of ~$1.2 billion year to date Nov 30, 2018 Balance Sheet Strength ~$2.6 billion Share Purchases ~$875 million Note: See Advisory for definitions. Capital expenditures exclude net acquisitions. BALANCED FREE CASH FLOW ALLOCATION 155 Free Cash Flow Allocation Policy Annual Adjusted Funds Flow Less: Budgeted Capital Expenditures Less: Dividends Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions 50% Free Cash Flow 50% Balance Sheet Strength Share Purchases Targets = 1.5x Debt/EBITDA and $15.0 billion in Absolute Debt Note: Policy is effective November 1, 2018 and targeted to be in place until at least the Company s Normal Course Issuer Bid renewal in May Policy to be reviewed quarterly by the Board of Directors. Please see Advisory for definitions. SUPPORTED BY STRONG BALANCE SHEET & SUSTAINABLE FREE CASH FLOW

82 Canadian Natural 2019 Targeted Free Cash Flow Scenarios: Impacts of Volatility ($ billion) $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 Free Cash Flow ~$2.9B (before dividends) Strip as at Dec 3, 2018 Free Cash Flow ~$3.1B (before dividends) Curtailment & Market Access Clarity Free Cash Flow ~$4.6B (before dividends) Strip as at Oct 19, Capital ($ billion) $3.7 $4.4 $4.7 Capital Free Cash Flow Note: Free cash flow represents adjusted funds flow less capital. See Advisory for cautionary statements, definitions and pricing assumptions. SUSTAINABLE FREE CASH FLOW 157 Canadian Natural Debt to Book Capitalization Improves Debt/Book Cap (%) 70% Financial Covenant 60% 50% 40% 30% 20% 10% 0% F 2019B* 2020F 2021F 2022F Actual Forecast *Reflects 2019 base capital budget. Note: 2019B to 2021F excludes impacts of IFRS 16, Lease Accounting. See Advisory for pricing assumptions and cautionary statements. ROBUST BALANCE SHEET

83 Returns to Shareholders Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Returns to Shareholders Defined free cash flow allocation policy Built in flexibility to maximize value Sustainable and growing dividend FLEXIBLE CAPITAL ALLOCATION MAXIMIZES SHAREHOLDER VALUE 159 Returns to Shareholders ($ million) 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 ~$8.9 billion returned to shareholders in 6 years Dividends Share Purchases & Distribution F Disciplined allocation of capital delivers sustainable dividend policy 18 consecutive years of dividend increases 22% increase to current quarterly dividend per common share over 2017 levels $1.34 per common share annualized ~$2.6 billion in share purchases and distributions, in last six years* 2018 share purchases total ~29.6 million shares for an aggregate total of ~$1.2 billion *Includes PrairieSky distribution and shares purchased from January 1, 2013 to November 30, ~22% OF CURRENT MARKET CAP RETURNED TO SHAREHOLDERS IN 6 YEARS

84 Canadian Natural Returns to Shareholders ($ million) 2,800 2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1, years of dividend increases 21% CAGR since inception Horizon Phase 1 build years F Dividend Share Purchase PSK Distribution Note: Based upon dividends declared. *2018F share purchases are YTD, as at November 30, HISTORY OF GROWING RETURNS TO SHAREHOLDERS YTD* 161 Returns to Shareholders Long Term Dividend Growth vs. Peers 10 Year CAGR (% CAGR) 30% 20% 10% CNQ 0% -10% -20% -30% Peers Integrated Peers Peers include: APA, APC, COP, DVN, ECA, EOG, HSE, IMO, NBL, MRO, OXY, SU. Note: CAGR calculated based upon dividend from Q3/08 to current Q3/18 annualized dividend. Source: Company reports. SIGNIFICANT LONG TERM SUSTAINABLE DIVIDEND GROWTH

85 Committed Management Management Ownership (% of Outstanding Shares) 2.5% 2.3% 2.0% 1.5% Substantial management and director invested wealth delivers clear alignment with shareholder interests 1.0% CNQ 0.5% 0.0% Peers Integrated Peers Peers include APC, APA, CVE, DVN, ECA, EOG, PXD and SU. Note: Based on share ownership data from Oct 2018 (excluding options). Outstanding shares as at Q2/18 for Canadian peers and as at Q3/18 for US peers per Bloomberg. Source: SEDI and BD Corporate. CONSISTENT HISTORY OF VALUE CREATION 163 Summary Committed to Balance Sheet strength and investment grade credit ratings Flexibility to manage through changing market conditions Flexible capital programs Optionality in maturity schedule and strong liquidity Access to capital markets Able to capture opportunities Committed to shareholder returns Through sustainable dividend and transparent share purchase policy Defined free cash flow allocation policy DELIVERING ON OUR FINANCIAL PLAN

86 Summary Tim McKay, President Canadian Natural A Unique E&P Company Built for All Cycles Long Life Low Decline asset base Low maintenance capital requirements Effective and efficient operations Flexible, disciplined free cash flow allocation Strong Balance Sheet, strengthening Liquids free cash flow breakeven of WTI ~US$39/bbl including dividends Disciplined & Delivering Real Value to Shareholders CFPS, EPS, Production per share growth Increasing ROCE, ROE, Dividend Yield Increasing returns to shareholders through dividends and share purchases Optionality to deliver significant long-term value growth with market access Massive low cost resource to develop Low price periods have minimal impact on corporate asset value ROBUST THROUGH THE CYCLES

87 Technology, Innovation & Continuous Improvement Leading R&D investor ~$3.1 billion invested since 2009 Benefits Unlocking reserves Becoming more effective and efficient Increasing production Reducing environmental footprint Canadian Natural s culture of leveraging technology, innovation and continuous improvement is everyone s accountability and is key to driving sustainable operations and long-term value TECHNOLOGY, INNOVATION & CONTINUOUS IMPROVEMENT = SUSTAINABILITY 167 Balancing the Four Pillars 2019 Plan Balance Sheet Strength Balance Sheet strengthens through free cash flow allocation policy Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions Returns to Shareholders Growing, sustainable dividends Share purchases through free cash flow allocation policy Economic Resource Development Disciplined corporate capital allocation Will be prudent to not create cost inflation Opportunistic Acquisitions No gaps in portfolio Must add value DISCIPLINED ALLOCATION, FOCUSED ON VALUE CREATION

88 Free Cash Flow Allocation Policy Annual Adjusted Funds Flow Less: Budgeted Capital Expenditures Less: Dividends Balance Sheet Strength Returns to Shareholders Economic Resource Development Opportunistic Acquisitions 50% Free Cash Flow 50% Balance Sheet Strength Share Purchases Targets = 1.5x Debt/EBITDA and $15.0 billion in Absolute Debt Note: Policy is effective November 1, 2018 and targeted to be in place until at least the Company s Normal Course Issuer Bid renewal in May Policy to be reviewed quarterly by the Board of Directors. Please see Advisory for definitions. SUPPORTED BY STRONG BALANCE SHEET & SUSTAINABLE FREE CASH FLOW 169 Key Message Increasing Returns Optimal Cash Flow Allocation Robust Throughout Cycles Unique, Balanced Asset Base Proven Effective Strategy A UNIQUE EXPLORATION & PRODUCTION COMPANY

89 Advisory Forward Looking Statements Certain statements relating to Canadian Natural Resources Limited (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, proposed or expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected future commodity pricing, forecast or anticipated production volumes, royalties, production expenses, capital expenditures, income tax expenses and other guidance provided throughout the Company's Management s Discussion and Analysis ( MD&A ) of the financial condition and results of operations of the Company, constitute forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands ("Horizon") operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Projects, the cost and timing of construction and future operations of the North West Redwater bitumen upgrader and refinery, construction by third parties of new or expansion of existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil ( SCO ) that the Company may be reliant upon to transport its products to market, development and deployment of technology and technological innovations and the assumption of operations at processing facilities also constitute forward-looking statements. This forwardlooking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year as 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 and proved plus probable crude oil, natural gas and natural gas liquids ( NGLs ) 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 and uncertainties 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 capital programs; the Company s and its subsidiaries ability to secure adequate transportation for its products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of 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 and in mining, extracting or upgrading the Company s bitumen products; availability and cost of financing; the Company s and its subsidiaries success of exploration and development activities and its ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies and assets; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, natural gas and NGLs 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 expenditures and production expenses); asset retirement obligations; the adequacy of the Company s provision for taxes; and other circumstances affecting revenues and expenses. The Company s operations have been, and in the future may be, affected by political developments and by national, 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 forwardlooking 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 factors is not exhaustive. Unpredictable or unknown factors not discussed in the Company's MD&A 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 applicable law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or the Company s estimates or opinions change.

90 Advisory Special Note Regarding Currency, Production and Reserves In this document, all references to dollars refer to Canadian dollars unless otherwise stated. Reserves and production data are presented on a before royalties basis unless otherwise stated. In addition, reference is made to crude oil, natural gas and NGLs in common units called barrel of oil equivalent ("BOE") or thousand cubic feet of gas equivalent ( McfGE ). A BOE is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil or NGLs (6Mcf:1bbl). An McfGE is derived by converting one barrel of crude oil or NGLs to six thousand cubic feet of natural gas (1bbl:6Mcf). These conversions may be misleading, particularly if used in isolation, since the 6Mcf:1bbl ratio or the 1bbl:6Mcf ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil or NGL prices relative to natural gas prices, the 6Mcf:1bbl or 1bbl:6Mcf conversion ratios may be misleading as an indication of value. This document, herein incorporated by reference, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board. For the year ended December 31, 2017 the Company retained Independent Qualified Reserves Evaluators ( IQREs ), Sproule Associates Limited and Sproule International Limited (together as Sproule ) and GLJ Petroleum Consultants Ltd. ( GLJ ), to evaluate and review all of the Company s proved and proved plus probable reserves with an effective date of December 31, 2017 and a preparation date of February 7, Sproule evaluated the North America and International light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), natural gas and NGLs reserves. GLJ evaluated the Horizon SCO reserves and reviewed the AOSP SCO reserves. The evaluation and review was conducted in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) and disclosed in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ) requirements. Reserves disclosure is presented in accordance with Canadian reporting requirements using forecast prices and escalated costs. The Company annually discloses net proved reserves and the standardized measure of discounted future net cash flows using 12-month average prices and current costs in accordance with United States Financial Accounting Standards Board Topic 932 Extractive Activities - Oil and Gas in the Company s Form 40-F filed with the SEC in the Supplementary Oil and Gas Information section of the Company s Annual Report. Special Note Regarding non-gaap Financial Measures The Company's MD&A should be read in conjunction with the unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the MD&A and the audited consolidated financial statements for the year ended December 31, All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company s unaudited interim consolidated financial statements for the three and nine months ended September 30, 2018 and the Company's MD&A have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ("IASB"). The Company's MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as: adjusted net earnings from operations; adjusted funds flow (previously referred to as funds flow from operations); net capital expenditures; adjusted cash production costs and adjusted depreciation, depletion and amortization. These financial measures are not defined by IFRS 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, cash flows from operating activities, and cash flows from investing activities as determined in accordance with IFRS, as an indication of the Company's performance. The non-gaap measure adjusted net earnings from operations is reconciled to net earnings, as determined in accordance with IFRS, in the Financial Highlights section of the Company's MD&A. The non-gaap measure adjusted funds flow is reconciled to cash flows from operating activities, as determined in accordance with IFRS, in the "Financial Highlights" section of the Company's MD&A. The non-gaap measure net capital expenditures is reconciled to cash flows from investing activities, as determined in accordance with IFRS, in the Net capital expenditures section of the Company's MD&A. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included in the "Operating Highlights - Oil Sands Mining and Upgrading" section of the Company's MD&A. The Company also presents certain non-gaap financial ratios and their derivation in the Liquidity and Capital Resources section of the Company's MD&A. A Barrel of Oil Equivalent ( BOE ) is derived by converting six thousand cubic feet ( Mcf ) of natural gas to one barrel ( bbl ) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A, crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO. Production volumes and per unit statistics are presented throughout the Company's MD&A on a before royalty or gross basis, and realized prices are net of blending and feedstock costs and exclude the effect of risk management activities. Production on an after royalty or net basis is also presented for information purposes only. Adjusted net earnings from operations is a non-gaap measure that represents net earnings as presented in the Company's consolidated Statements of Earnings, adjusted for certain items of a non-operational nature. The Company considers adjusted net earnings from operations a key measure in evaluating the Company's performance. The reconciliation Adjusted Net Earnings from Operations presented in this MD&A, presents the after-tax effects of certain items of a non-operational nature that are included in the Company s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. Adjusted funds flow (previously referred to as funds flow from operations) is a non-gaap measure that represents cash flows from operating activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, and abandonment and other expenditures. The Company evaluates its performance based on adjusted funds flow. The Company considers adjusted funds flow a key measure as it demonstrates the Company s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation Adjusted Funds Flow, as Reconciled to Cash Flows from Operating Activities is presented below in this MD&A. Adjusted funds flow may not be comparable to similar measures presented by other companies. Net capital expenditures is a non-gaap measure that represents cash flows from investing activities as presented in the Company's consolidated Statements of Cash Flows, adjusted for the net change in non-cash working capital, investment in other long-term assets, share consideration in business acquisitions and abandonment expenditures. The Company considers net capital expenditures a key measure as it provides an understanding of the Company s capital spending activities in comparison to the Company's annual capital budget. The reconciliation Net Capital Expenditures, as Reconciled to Cash Flows from Investing Activities is presented in the Net Capital Expenditures section of this MD&A on page 25. Net capital expenditures may not be comparable to similar measures presented by other companies. Additional information relating to the Company, including its Annual Information Form for the year ended December 31, 2017, is available on SEDAR at and on EDGAR at

91 Advisory Cautionary Statement Project progress and financial results are dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Definitions & non-gaap Measures Absolute Debt see definition for total debt. Adjusted EBITDA earnings before interest, taxes, depletion and amortization adjusted for stock based compensation expenses/(recovery), unrealized risk management gains/(losses), unrealized foreign exchange gains/(losses), and accretion expenses of the Company s asset retirement obligation. CAGR Compound Annual Growth Rate the compounded growth rate for a specific value on an annual basis in a defined time range. CFPS Cash Flow per Share adjusted funds flow (see the Company s MD&A for definition) divided by the weighted average common shares outstanding at the end of the period. Debt to EBITDA long-term debt plus the current portion of long-term debt divided by the 12 month trailing adjusted EBITDA Debt per Net BOE Reserves long-term debt plus the current portion of long-term debt divided by Company net (before royalties) reserves on a BOE basis. Dividend Yield annualized dividend declared divided by current share price. FD&A Finding, Development and Acquisition costs the sum of total exploration, development and acquisition capital costs divided by total reserves additions and revisions for the relevant reserve category. Free Cash Flow adjusted funds flow (see the Company s MD&A for definition) less net capital expenditures and current dividends. Operating free cash flow operational cash flow before administration costs, interest, foreign exchange and taxes less net capital expenditures before acquisitions of non-producing properties, capitalized interest and capitalized stock based compensation. Operating Netback production revenues, excluding realized gains and losses on commodity hedges, less transportation and blending, royalties and production expenses on a per unit basis. Production per Share average net production volumes divided by weighted average diluted common shares outstanding at the end of the period. ROCE Return on Capital Employed net earnings plus after-tax interest and other financing expenses for the 12 month trailing period divided by the average capital employed for the period. ROE Return on Equity net earnings for the 12 month trailing period divided by average common shareholders equity for the period. Recycle Ratio operating netback divided by the FD&A. Total Debt long-term debt and current portion of long-term debt. Pricing Assumptions Strip (1) 2018F 2019B 2020F 2021F 2022F Base Budget Normalized Budget October 29, 2018 US$ WTI/bbl $ $ $ $ $ $ $ C$ AECO/GJ $ 1.44 $ 1.26 $ 1.26 $ 1.48 $ 2.35 $ 2.70 $ 2.89 SCO Diff/(prem) US$/bbl $ 6.16 $ 8.81 $ 6.25 $ 5.50 $ 1.20 $ (1.25) $ (1.96) WCS Differential US$/bbl $ $ $ $ $ $ $ FX 1.00 US$ = X C$ $ $ $ $ $ $ $ FX 1.00 GBP = X C$ $ $ $ $ $ $ $ (1) 2018F reflects strip pricing as of November 16, B reflects strip pricing as of December 3, F-2022F reflects average Sproule, GLJ and McDaniels & Associates pricing forecasts as of October 2018.

92 Advisory Reserves Notes: (1) Company Gross reserves are working interest share before deduction of royalties and excluding any royalty interests. (2) Company Net reserves are working interest share after deduction of royalties and including any royalty interests. (3) BOE values may not calculate due to rounding. (4) Forecast pricing assumptions utilized by the Independent Qualified Reserves Evaluators in the reserves estimates were provided by Sproule Associates Limited: Average annual increase thereafter Crude oil and NGL WTI at Cushing (US$/bbl) $ $ $ $ $ % Western Canada Select (C$/bbl) $ $ $ $ $ % Canadian Light Sweet (C$/bbl) $ $ $ $ $ % Cromer LSB (C$/bbl) $ $ $ $ $ % Edmonton Pentanes+ (C$/bbl) $ $ $ $ $ % North Sea Brent (US$/bbl) $ $ $ $ $ % Natural gas AECO (C$/MMBtu) $ 2.85 $ 3.11 $ 3.65 $ 3.80 $ % BC Westcoast Station 2 (C$/MMBtu) $ 2.45 $ 2.71 $ 3.25 $ 3.40 $ % Henry Hub (US$/MMBtu) $ 3.25 $ 3.50 $ 4.00 $ 4.08 $ % Note: A foreign exchange rate of US$/C$ for 2018, US$/C$ for 2019, and US$/C$ after 2019 was used in the 2017 evaluation. (5) A barrel of oil equivalent ( BOE ) is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. (6) Metrics included herein are commonly used in the oil and natural gas industry and are determined by Canadian Natural as set out in the notes below. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies and may be misleading when making comparisons. Management uses these metrics to evaluate Canadian Natural s performance over time. However, such measures are not reliable indicators of Canadian Natural s future performance and future performance may vary. (7) Reserves additions and revisions are comprised of all categories of Company Gross reserves changes, exclusive of production. (8) Reserves replacement or Production replacement ratio is the Company Gross reserves additions and revisions, for the relevant reserves category, divided by the Company Gross production in the same period. (9) Reserves Life Index is based on the amount for the relevant reserves category divided by the 2018 proved developed producing production forecast prepared by the Independent Qualified Reserves Evaluators. (10) Finding, Development and Acquisition ("FD&A") costs are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2017 by the sum of total additions and revisions for the relevant reserves category. (11) FD&A costs including change in Future Development Capital ("FDC") are calculated by dividing the sum of total exploration, development and acquisition capital costs incurred in 2017 and net change in FDC from December 31, 2016 to December 31, 2017 by the sum of total additions and revisions for the relevant reserves category. FDC excludes all abandonment and reclamation costs. (12) Recycle Ratio is the operating netback ($23.40/BOE for 2017) divided by the FD&A (in $/BOE). Operating netback is production revenues, excluding realized gains and losses on commodity hedging, less royalties, transportation and production expenses, calculated on a per BOE basis

93 Key Historic Data Operational & Financial Information Ratios Daily production, before royalties Crude oil and NGLs (Mbbl/d) Natural gas (MMcf/d) 1,220 1,158 1,555 1,726 1,691 1,662 Barrels of oil equivalent (MBOE/d) Daily production, after royalties Crude oil and NGLs (Mbbl/d) Natural gas (MMcf/d) 1,190 1,104 1,432 1,667 1,627 1,587 Barrels of oil equivalent (MBOE/d) Proved reserves, after royalties Crude oil and NGLs (MMbbl) 1,677 1,767 1,898 1,864 1,922 2,070 Natural gas (bcf) 3,670 3,813 5,173 5,443 5,909 6,068 Mining reserves, SCO (MMbbl) 1,891 1,827 1,764 2,013 2,195 4,543 Barrels of oil equivalent (MMBOE) 4,179 4,230 4,524 4,784 5,102 7,625 Drilling activity, net wells Crude oil 1,203 1,117 1, Natural gas Dry Strats and service Realized product pricing, before hedging activities & after transportation costs Crude oil and NGLs (C$/bbl) (1) Oil Sands Mining and Upgrading (C$/bbl) Natural gas (C$/Mcf) Results of operations (C$ million, except per share) Adjusted funds flow 6,013 7,477 9,587 5,785 4,293 7,347 per share Basic Net earnings (loss) 1,892 2,270 3,929 (637) (204) 2,397 per share Basic (0.58) (0.19) 2.04 Capital expenditures (net, including combinations) 6,308 7,274 11,744 3,853 3,794 17,129 Balance Sheet Info (C$ million) Property, plant and equipment (net) 44,028 46,487 52,480 51,475 50,910 65,170 Total assets 48,980 51,754 60,200 59,275 58,648 73,867 Long-term debt 8,736 9,661 14,002 16,794 16,805 22,458 Shareholders equity 24,283 25,772 28,891 27,381 26,267 31,653 Debt to adjusted funds flow, trailing 12 months 1.5x 1.3x 1.4x 2.6x 3.5x 3.1x Debt to book capitalization 26% 27% 33% 38% 39% 41% Return on common equity, trailing 12 months 8% 9% 14% (2%) (1%) 8% Daily production before royalties per 10,000 common shares Proved and probable reserves before royalties (BOE) per common share* Share information Common shares outstanding (thousands) 1,092,072 1,087,322 1,091,837 1,094,668 1,110,952 1,222,769 Weighted average common shares Basic (thousands) 1,097,084 1,088,682 1,091,754 1,093,862 1,100,471 1,117,094 Dividend per share (C$) TSX trading info High (C$) Low (C$) Close (C$) (1) Realized pricing for exploration and production segments only.

94 Steve W. Laut Executive Vice-Chairman Tim S. McKay President Darren Fichter Chief Operating Officer, Exploration and Production Scott G. Stauth Chief Operating Officer, Oil Sands Corey B. Bieber Chief Financial Officer and Senior Vice-President, Finance Mark Stainthorpe Vice President, Finance Capital Markets Jason Popko Manager, Investor Relations (403) Lance Casson Analyst, Investor Relations (403) Priya Rai Analyst, Investor Relations (403) CANADIAN NATURAL RESOURCES LIMITED 2100, 855-2nd Street S.W., Calgary, Alberta, T2P 4J8 Phone: (403)