2014 BUDGET SUMMARY - Canadian Natural...

2014 Budget Summary November 7, 2013

1

PROVEN EFFECTIVE STRATEGY

2014 BUDGET SUMMARY

November 7, 2013

CNQ

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” or “targeted”, “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 of plans relating to and expected results of existing and future developments, including but not limited to the Horizon Oil Sands operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Projects, construction of the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast, construction of the proposed Northern Gateway Pipeline from Edmonton, Alberta to Kitimat British Columbia ,construction of the proposed Energy East pipeline to transport crude oil from Alberta to Quebec and New Brunswick, the proposed Kinder Morgan Trans Mountain pipeline expansion from Edmonton, Alberta to Vancouver, British Columbia, and the construction and future operations of the North West Redwater bitumen upgrader and refinery 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 and the reader should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or expectations upon which they are based will occur. In addition, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil and 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 their ability to replace and expand crude oil and natural gas reserves; timing and success of integrating the business and operations of acquired companies; production levels; imprecision of reserve estimates and estimates of recoverable quantities of crude oil, 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 and operating costs); 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 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. For additional information refer to the “Risks Factors” section of the AIF. Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements. Although the Company believes that the expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the foregoing factors affecting this information, should circumstances or Management’s estimates or opinions change.

Forward Looking Statements

Slide 2


2

CNQ

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 and natural gas in common units called barrel of oil equivalent ("BOE"). A BOE is derived by converting six thousand cubic feet of natural gas to one barrel of crude oil (6Mcf:1bbl). This conversion may be misleading, particularly if used in isolation, since the 6Mcf:1bbl ratio is based on an energy equivalency 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 6Mcf:1bbl conversion ratio 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, 2012 the Company retained Independent Qualified Reserves Evaluators (“Evaluators”), 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, 2012 and a preparation date of February 11, 2013. 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. 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 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) requirements. In previous years, Canadian Natural had been granted an exemption order from the securities regulators in Canada that allowed substitution of U.S. Securities Exchange Commission (“SEC”) requirements for certain NI 51-101 reserves disclosures. This exemption expired on December 31, 2010. As a result, the 2011 and 2012 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 targeted to be released in late March 2013. Resources Other Than Reserves The contingent resources other than reserves (“resources”) estimates provided in this presentation are internally evaluated by qualified reserves evaluators in accordance with the COGE Handbook as directed by NI 51-101. No independent third party evaluation or audit was completed. Resources provided are best estimates as of December 31, 2012. The resources are evaluated using deterministic methods which represent the expected outcome with no optimism or conservatism. Resources, as per the COGE Handbook definition, are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but are not currently considered commercially viable due to one or more contingencies. There is no certainty that it will be commercially viable to produce any portion of these resources. Due to the inherent differences in standards and requirements employed in the evaluation of reserves and contingent resources, the total volumes of reserves or resources are not to be considered indicative of total volumes that may actually be recovered and are provided for illustrative purposes only. Crude oil, bitumen or natural gas initially-in-place volumes provided are discovered resources which include production, reserves, contingent resources and unrecoverable volumes. Special Note Regarding non-GAAP Financial Measures This document includes references to financial measures commonly used in the crude oil and natural gas industry, such as cash flow from operations, adjusted net earnings from operations, cash production costs, and net asset value. 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, as determined in accordance with IFRS, as an indication of the Company’s performance. The non-GAAP measures adjusted net earnings from operations and cash flow from operations are reconciled to net earnings, as determined in accordance with IFRS in the “Financial Highlights” section of the Company’s MD&A which is incorporated by reference into this document. The derivation of cash production costs is included in the “Operating Highlights – Oil Sands Mining and Upgrading” section of the Company’s MD&A which is incorporated by reference into this document. The volumes shown are Company share before royalties unless otherwise stated.

Slide 3

CNQ PREMIUM VALUE | DEFINED GROWTH | INDEPENDENT Slide 4

Q3/13 Highlights

• Record quarterly production

‒703,000 boe/d

‒509,000 bbl/d crude oil & NGLs

• Record primary heavy crude oil production

• Record Pelican Lake crude oil production

• Kirby South commissioned ahead of schedule, on budget

• Horizon reliable operations

‒112,000 bbl/d

• Septimus expansion on-stream

‒September - 125 MMcf/d - 12,200 bbl/d liquids

• South Africa partner finalization, validated value

• Strong crude oil pricing

• Very strong cash flow and earnings

• Dividend increase to $0.20 per quarter – 60% increase


3

CNQ

Prudent Balance Sheet Management

• History of prudent Balance Sheet management

‒ Strong Balance Sheet metrics

• Confidence in the Defined Plan

‒ Sustainability of cash flow stream through the business cycle

‒ Capital flexibilty supports effective capital allocation and downside protection

‒ Prudent hedging practices affords additional downside protection

• 60% Dividend increase - $0.20 per quarter

‒ Strong endorsement of our confidence in the defined plan and sustainability of

free cash flow

‒ 14 consecutive years of sustainable dividend increases

31% CAGR since 2009

‒Growing the business and returning shareholder value

PREMIUM VALUE | DEFINED GROWTH | INDEPENDENT Slide 5

Prudent Use of Cash Flow

2013F 2014B

Debt/Book 26.4% 25.4-26.2%

Debt to EBITDA 1.01x 1.0-1.05x

CNQ

$0.05 $0.02 $0.01

$0.02 $0.02

$0.03 $0.02

$0.03 $0.01

$0.09

$0.06

$0.06

$0.08

$0.30

$0.05 $0.07 $0.08

$0.10 $0.12

$0.15 $0.17

$0.20 $0.21

$0.30

$0.36

$0.42

$0.50

$0.80

0.00%

0.50%

1.00%

1.50%

2.00%

2.50%

3.00%

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

$0.90

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013F 2014B

CNQ Annual Dividend Increase

Note: Dividend restated to reflect two-for-one share splits in May 2010, May 2005 and May 2004. Dividend yield based on weighted average share price for years

2001-2012 and based on share price of $32.50 for 2013F and 2014B.

Dividend Increase - 40% 14% 25% 20% 27% 13% 18% 5% 43% 20% 17% 19% 60%

Dividend Per Share ($) Annual Increase ($) Dividend Yield (%)



4

CNQ

Canadian Natural Advantage

Value Growth

Driven by

• Effective capital allocation

• Effective and efficient operations

• Strong Management teams

Our Strategy Works

Near term growth

requirements

Increasing Free

Cash Flow to Allocate

Large Resource

Base

Return to Shareholders (Dividends /Repurchases)

Balance Sheet (Repay debt)

Opportunistic

Acquisitions

Increased Asset

Strength

Strong Balanced

Asset Base Free

Cash Flow


CNQ

Size of Canadian Natural Reserve Base

2012 1P Reserves After Royalties

Significant Value to Unlock

Note: Per BMO Capital Markets Research - 2012 Oil & Gas Global Cost Study.

Peers include: APA, APC, EOG, CVE, CHK, DVN, ECA, HSE, IMO, OXY, NBL, SU, TLM.


(MMBOE)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

CNQ


5

CNQ

Size of Canadian Natural Reserve Base

2012 2P Reserves Before Royalties


Significant Value to Unlock

(MMBOE)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Based on forecast pricing assumptions.

Note: Sourced from 2012 corporate reports. Peers include: CVE, ECA, HSE, IMO, SU, TLM.


Large Resource Base to Develop

Vast Resource Base Holds Significant Future Value

0

5,000

10,000

15,000

20,000

25,000

Reserves* Resources** Reserves & Resources

*Company gross proved and probable reserves at December 31, 2012.

**Company gross best estimate contingent resources other than reserves at December 31, 2012.

Note: Contingent resource includes Thermal, Pelican Lake, Horizon, Montney and Deep Basin.

Please see reporting disclosures for additional information.

7,886

14,529

(MMBOE)

22,415 Gross Proved Reserves*

Gross Probable Reserves*

Resources**


6


Long Life Assets = More Sustainable Cash Flow

Transitioning to a Longer Life Asset Base

0%

10%

20%

30%

40%

50%

60%

70%

2007 2011 2015F 2018F

Horizon - Sold as Synthetic Crude Oil

Thermal In Situ - Sold as Heavy Crude Oil

Pelican Lake - Sold as Heavy Crude Oil

*2015F - 2018F based on company internal forecast as at May 2013. Dependent upon economic and regulatory conditions, commodity prices, global

economic factors, project sanction and capital allocation.

(% of CNQ liquids production)*

CNQ

$0

$1

$2

$3

$4

$5

$6

$7

2013F 2014B 2015F 2016F 2017F 2018F 2019F 2020F 2021F 2022F

Canadian Natural

Targeted Total Corporate Free Cash Flow


Free Cash Flow Growing to the Wall of Free Cash Flow

Note: Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Free cash flow represents cash flow (cash flow net of corporate costs, interest, foreign exchange and taxes) less capital before dividends and share repurchases. Capital targeted between $7.0 and $7.8 billion for 2013F-2017F and significantly less thereafter. 2013F and 2014B based upon Nov. 7 guidance and budget numbers – see website for pricing assumptions. 2015F to 2017F based upon constant pricing assumptions forecasted at May 2013; WTI of US$94.95/bbl, AECO of C$3.50/GJ-C$4.00/GJ, and WCS differential of 26%. 2018F to 2022F based upon average strip pricing assumptions forecasted at May 2013; WTI of US$82.75/bbl, AECO of C$4.82/GJ, and WCS differential of 22%.

($ billion)


7

CNQ

Free Cash Flow Uses

1. Resource development

‒ Executing our defined plan

2. Dividends

‒ 14 consecutive years of dividend increases

31% CAGR (2009 – 2014)

‒ Must be sustainable

3. Share purchases

‒ 11.0 million common shares purchased at an average price of

$28.91/share in 2012


$31.13/share YTD

4. Opportunistic acquisitions

5. Pay down debt



CNQ

0

100

200

300

400

500

600

700

800

900

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013F

Dividend Share Purchase

Horizon build years

Balanced Free Cash Flow Allocation


($ million) Return to Shareholders

Note: CAGR represents 2009-2013F. 11.0 million common shares purchased in 2012 at a weighted average price of $28.91/share. Year to date, 9.26 million

common shares have been purchased in 2013 at a weighted average price of $31.13/share.


8

CNQ

2014 Targeted Free Cash Flow Uses


($ million) 2013F 2014B

Expected Cash Flow $ 7,640 $8,700

Capital Program 7,175 7,700

Free Cash Flow 465 1,000

Dividends $523 $870

Share Purchase* 300 ?

Flex Capital Program** - 0 - 400

Balance Sheet – (Build)/Draw $(358) $(270) - $130

Debt/Book 26.4% 25.4 - 26.2%

Debt/EBITDA 1.04x 1.0 - 1.05x

*Dependent on CNQ share price and commodity prices. **Dependent on construction market conditions at Horizon Projects. Note: Does not include any potential Montney land sale proceeds.

CNQ

0

200

400

600

800

1,000

1,200

2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013F 2014

Dividend Share Purchase

Horizon build years

Balanced Free Cash Flow Allocation


($ million) Return to Shareholders

Potential

Note: CAGR represents 2009-2014 Potential. 11.0 million common shares purchased in 2012 at a weighted average price of $28.91/share. Year to date,

9.26 million common shares have been purchased in 2013 at a weighted average price of $31.13/share.

?


9

CNQ

Canadian Natural

2014 Budget Summary

2014B

Cash Flow $8.7 billion

Capital $7.7 - 8.1 billion

Crude oil & NGLs production growth 9% growth

Capital for future production $3.6 billion ~45%

Capital flexibility in original budget $3.2 billion

2013F 2014B

Production (MBOE/d) 663 - 704 711 - 757

Year End Debt ($ billion) $9.2 - 9.6 $9.6 - $10.0

Year End Debt / Book* 26.4% 25.4 - 26.2%


Focused on Value Creation

Note: 2014 Strip Pricing: WTI US$96.67, AECO C$3.47/GJ, C$/US$ $0.96.

*Midpoint of Guidance.

CNQ

Canadian Natural

2014 Capital Budget Capital ($ million) 2013F 2014B

Natural gas $540 $590

Crude oil

Pelican Lake 400 245

Primary Heavy 1,125 1,200

Thermal In Situ 1,260 1,130

Light

Canada 530 545

North Sea 350 470

Offshore Africa 160 280

Total crude oil $3,825 $3,870

Horizon

Sustaining Capital 290 260

Turnarounds, Reclamation & Other 270 330

Capital Projects 2,035 2,520 - 2,920

Technology and Phase 4 25 35

Total Horizon $2,620 $3,145 - 3,545

Acquisitions, Midstream & Other 190 135

Total $7,175 $7,740 - 8,140


Developing Highest Return on Capital, Balanced Near-, Mid- and Long-Term


10

CNQ

Canadian Natural

2014 Production Budget

Targeted Production 2013F* 2014B* %Change

Crude oil (Mbbl/d)

North America Light Oil & NGLs 65-69 72-76

Pelican Lake 46-50 47-51

Primary Heavy 139-143 142-146

Thermal In Situ Oil Sands 100-107 120-135

International 32-36 33-37

Horizon Oil Sands 100-108 107-115

Total Crude Oil & NGLs 482-513 521-560 9%

Natural Gas (MMcf/d) 1,085-1,145 1,140-1,180 4%

MBOE/D 663-704 711-757 7%


Strategic, Defined Growth Plan

*Rounded to the nearest 1,000 bbl/d.

Note: Numbers may not add due to rounding.

CNQ

North American Crude Oil Markets

Canadian Natural’s Viewpoint

• Pipeline/transportation infrastructure is complex

‒Misconceptions are common

• Significant North American heavy oil demand

‒260,000 bbl/d PADD II demand increase

‒3,000,000+ bbl/d Gulf Coast demand

• Opportunities provided by existing infrastructure projects

‒ Mainline optimization 400,000 bbl/d

‒ Flanagan South Q2-2014 600,000 bbl/d

‒ Keystone XL Q4-2015 830,000 bbl/d

‒ Gateway 525,000 bbl/d

‒ TMX 890,000 bbl/d

‒ Energy East 1,100,000 bbl/d

• Rail to fill in any pipeline shortfalls


Oil Transportation Issues Manageable


11

CNQ

Asset Overview


CNQ

North America Natural Gas

Core Area Summary

• 2nd largest producer of

natural gas in Canada

• Large resource base

‒ 5.6 Tcf 2P reserves*

‒ Significant unconventional

assets

Montney and Duvernay

• Proved and unproved

land position

‒ 16.2 million net acres

• High working interest

• Dominant infrastructure

• $1 increase in AECO =

~$310 million additional

annual cash flow**


Strong Asset Base

*Company Gross proved plus probable reserves at December 31, 2012.

**Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation.

Note: Reflects Q3/13 actual production, before royalties. Does not include NGLs production.

NEBC

347 MMcf/d

BC

AB SK

Northern Plains

163 MMcf/d

NW Alberta

463 MMcf/d

Southern Plains

163 MMcf/d

CNQ Land

Calgary

Edmonton

Fort St. John

MB


12

CNQ

0 200,000 400,000 600,000 800,000 1,000,000 1,200,000


Top Montney Land Holders by Net Acres

• Largest Unconventional Land Base


Canadian Natural ~1,043,800 Net Acres

~243,000 acres Potential Sale

CNQ internal and Cormark Reports (June 2013) for peers.

Peers include: ARX, BIR, CLT, ECA, GO, MUR, POU, PRQ, RDS, TLM, TOU.

Duvernay Lands ~500,000 Net Acres

CNQ

2013F 2014B % Change

Production (MMcf/d) 1,065-1,135 1,100-1,140 2%

Drilling (net wells) 42 61

Capital ($ million) $540 $590


2014 Plan


Most Efficient and Effective Producer

• Capital discipline

• Significant flexibility to quickly respond to strengthening gas prices

• Efficient and effective operations provide operating free cash flow

• Preserve land base for increasing gas prices

• In midst of process to potentially monetize approximately ~243,000 net acres of

liquids rich Montney land


13

CNQ

Thermal In Situ Oil Sands

Tremendous Potential


Massive Resource to Exploit

McMurray

49 billion barrels

Wabiskaw

9 billion barrels

Carbonates

10 billion barrels

Clearwater

14 billion barrels

Grand Rapids

15 billion barrels

97 billion barrels total BIIP*

*Discovered Bitumen Initially in Place.

**Company Gross proved plus probable reserves as at December 31, 2012.

***Best estimate contingent resources other than reserves as at December 31, 2012.

Produced to Date 0.4 billion bbl

Resources*** 8.4 billion bbl

Probable Reserves** 1.0 billion bbl

Proved Reserves** 1.1 billion bbl

CNQ


Growth Plan

Phase Reservoir

Oil Facility

Capacity Target

(bbl/d)

Target Steam-In

Timing

(year)

Primrose South/North – CSS Clearwater 80,000 On Stream

Primrose East – CSS Clearwater 40,000 On Stream

Kirby South – SAGD McMurray 40,000 On Stream

Kirby North Phase 1 – SAGD McMurray 40,000 2016

Grouse – SAGD McMurray 40,000 2017-2019

Primrose Expansion – CSS / SAGD Clwtr/GrRpds 50,000 2020-2021

Kirby North Phase 2 – SAGD Wabiskaw 60,000 2022-2023

Gregoire Phase 1 – SAGD McMurray 60,000 2024-2025

Pelican – SAGD Grand Rapids 40,000 2026-2027

Gregoire Phase 2 – SAGD McMurray 60,000 2028-2029


Significant Potential – Taking the Time to Do It Right

• 510,000 bbl/d of oil facility capacity in the defined growth plan

• 40,000-60,000 bbl/d addition every 2-3 years

• 100% working interest and operatorship


14

CNQ


2014 Plan

2013F 2014B %Change

Production (Mbbl/d) 100-107 120-135 23%

Drilling (net wells)

Primrose producers 134 15

Kirby South producers 8 -

Strats 73 130

Service / observation wells 64 54

Total 279 199

Capital ($ million) $1,260 $1,130


Continued Volume Growth with Long Term Focus on Spending

Note: Rounded to the nearest 1,000 bbl/d.

CNQ

Primrose Seepage to Surface Update

• Seepage contained

• Cleanup >80% complete

• Causation review well underway

• Confident wellbore failure is root cause



15

CNQ

Primrose Causation Review Update

Wellbore Pathway


• Clearwater reservoir is

500m deep

• 3 barriers

‒Clearwater Shale

‒Grand Rapids Formation

‒Colorado Group Shales

Paleo

CNQ

Primrose Causation Review Update

• Working well with the AER

• Results to date:

‒4 legacy wells identified as likely wellbore failures

‒2 of 4 have identified mechanical failures

Further delineation required to prove conclusively

‒1 under investigation

‒1 waiting on access

• Over entire Primrose area 31 legacy wells identified as high risk

potential wellbore failure candidates

‒16 are within 1 kilometer of areas to be steamed in 2014

‒1 confirmed as inadequate and repaired

‒1 confirmed as adequate and equipped with enhanced monitoring

‒14 waiting on access



16

CNQ

Primrose Plan – Going Forward*

• All wells, including old legacy wells, thoroughly reviewed for the

potential to fail mechanically

• All wells with identified potential to fail will be repaired prior to

additional steaming

• Enhanced monitoring of any potential release from Clearwater into

Grand Rapids

• Enhanced response to subsurface releases to Grand Rapids

‒Cease injection into Clearwater

‒And/or blowdown horizontal injector/producer

• Modified steam injection volumes

‒Reduction in steam volume growth as cycles progress

• Convert Primrose East to steam flooding after initial steam cycles


*Subject to AER approval.

CNQ

Primary Heavy Crude Oil

Core Area Summary

• Largest primary producer

in Canada

• 2P reserves

‒284 million barrels*

• Dominant land base and

infrastructure

‒Over 8,500 drilling locations

‒5 major processing facilities

‒ECHO sales pipeline

Vast Land Base and Infrastructure Captures Value

~138 Miles

ECHO Pipeline

CNQ Producing

Properties

CNQ Lands

*Company Gross proved plus probable reserves as at December 31, 2012.



17

CNQ

2013F 2014B %Change


Drilling (net wells) 852 898

Recompletion (net wells) 565 503

Capital ($ million) $1,125 $1,200

Primary Heavy Crude Oil

2014 Plan

• Tremendous potential through technology advancements

• Low operating costs strong netbacks

• High return on capital


Strong Cash on Cash Returns


CNQ

• Massive Wabiskaw heavy crude oil pool

• Industry leading EOR project

‒ Amongst the largest polymerfloods in

the world

‒ Technology development continues

to improve crude oil recovery

‒ Leading example of technology

driving value growth

• Industry leading operating costs

• Strong operating free cash flow

Pelican Lake Crude Oil Pool


Massive Resource to Exploit

How much of that crude oil

is recoverable?

OIIP*

4.1

billion

barrels

Developed

Region

18% RF

Produced to Date 181 MMbbl

Resources*** 204 MMbbl

Probable Reserves** 105 MMbbl

Proved Reserves** 267 MMbbl

*Discovered heavy crude oil initially in place.

**Company Gross proved plus probable reserves as at December 31, 2012.

***Best estimate contingent resources other than reserves as at December 31, 2012.


18

CNQ

2013F 2014B %Change

Production (bbl/d) 46-50 47-51 2%

Drilling (net wells) – Producers 33 17


Pelican Lake

2014 Plan

• Increasing free cash flow wedge as capital requirements are reduced and

polymer driven performance is realized


Technology Advancement Can Provide Significant Upside


CNQ

North America Light Crude Oil and NGLs

2014 Plan

• 2014 forecast activity

‒ Drill 93 wells

‒ Target multiple formations across basin

• Leverage technology, horizontal multifracs

‒ 80% of total drilling – Horizontal

• 1.4 million net acres of Triassic lands to develop


Grande Prairie Focus = Steady Growth


Production* (Mbbl/d) 65-69 72-76 10%

Drilling (net wells) – Producers 109 93



*Includes NGLs.


19

CNQ

International Light Crude Oil

2014 Plan

• 2P light crude oil reserves 490 million barrels*

• Light oil balance in portfolio Brent pricing

• Exposure to offshore operations and geographic diversification in asset base

‒ North Sea

5 net production wells and 2 net injectors planned in 2014

‒ Offshore Africa

Espoir development targeted for 2nd half of 2014

1 exploration well expected for 2014 on Block 514 in Côte d’Ivoire

36% working interest


Free Cash Flow Generation

2013F 2014B %Change

Crude oil production (Mbbl/d) 32-36 33-37 3%



*Company gross proved plus probable reserves at December 31, 2012..

CNQ

International Light Crude Oil

South Africa

• Partnering with Total

SA (50% WI, Total

as operator)

• 5 structures ranging

up to 1 billion barrels

• First exploration well

targeted to be drilled

in 2014

• Partner to carry the

costs of first

exploration well up

to US$150 million

• Long lead

equipment ordered


High Impact Potential

Mossel Bay Plettenberg Bay

South Africa

Canadian Natural

Block 11B/12B

Superior

Gas Discovery

Sable

Oil Field

FA Gas Field

Oryx & Oribi

Oil Fields

FO Gas Field


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CNQ

Horizon Oil Sands

Core Area Summary

• World Class asset

• 14.4 billion barrels BIIP*

‒ 2P SCO reserves – 3.4 billion barrels**

‒ Best estimate contingent resources other

than reserves – 3.3 billion barrels of

bitumen***

• Phased development (SCO)

‒ 110,000 bbl/d capacity (Phase 1)

‒ Targeted completion of Phase 2/3

to 250,000 bbl/d

‒ Potential future expansion to ~500,000

bbl/d of SCO or Bitumen equivalent

• 40+ years of production with no declines

• 100% working interest

• Significant free cash flow generation

for decades


World Class Opportunity

UTS

SYN

SHC

SYN

SYN

DVN

PCA SU

PCA

IOL

ECA

SU

SU

IOL

HSE

XOM

SHC

SU

Synenco SHC

XOM

ECA

ECA

Deer Creek

SU

Fort

McMurray

~4

3 m

ile

s

CNQ

CNQ

CNQ

Horizon Oil Sands

*Discovered Bitumen Initially in Place. **Company Gross proved plus probable reserves as at December 31, 2012. ***Best estimate contingent resources other than reserves as at December 31, 2012.

CNQ

Horizon Oil Sands

2014 Operations Plan

• Enhance reliability

‒8% unplanned downtime post turnaround in 2013

6% - North America refinery average

• Greater focus on operating cost reductions

‒2014 Guidance: $36.00–$39.00/bbl

• Early completion of Coker expansion

‒Debottlenecking tie-ins, August 2014

‒Outage to complete tie-in 20-25 days

• Increase stream day capacity to 133,000 bbl/d



21

CNQ



Sustaining Capital ($ million) $290 $260

Turnarounds, Reclamation & Other ($ million)

$270 $330

Operating Cost ($/bbl)* $42.50 - $44.50 $36.00 - $39.00

Horizon Oil Sands

2014 Operations Plan


Focus on Operational Excellence


*2013F and 2014B operating costs reflects production downtime.

CNQ

2013F 2014B

Project Capital ($ million)

Reliability – Tranche 2 $90 $40

Directive 74 55 200

Phase 2A 165 100

Phase 2B 1,005 1,325-1,575

Phase 3 495 550-700

Owner’s Costs & Other 225 305

Total $2,035* $2,520-2,920*

Horizon Oil Sands

2014 Plan – Project Expansion Capital

• CNQ execution strategy is working

‒ Cost tracking on or below budget which has opened up a window of opportunity

for increased expansion expenditures


Focus on Operational Excellence

*Excludes Technology and Phase 4 project capital.


22

CNQ

Horizon Oil Sands

Production Capacity Plan*

• Moving Phase 2A into 2014*


Future Expansion 110 Mbbl/d up to 250 Mbbl/d

75,000

100,000

125,000

150,000

175,000

200,000

225,000

250,000

275,000

300,000

2012 2013F 2014B 2015F 2016F 2017F 2018F 2019F

Forecast/Budget Capacity Target

(bbl/d)

12 Mbbl/d

added

45 Mbbl/d

added

80 Mbbl/d

added

Phase 2A* Phase 2B Phase 3

Note: Capacity additions – 3-6 months required to ramp up to full rates. Project progress dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. 2013F - 2019F based on Company internal forecast as at Nov. 2013.

CNQ

Horizon Oil Sands

Targeted Fixed vs. Variable Operating Costs

• Labour is a major portion of fixed costs

• Production increases 2.4x while labour increases 1.4x

• Introduction of thickeners, saves energy, reduces cost

• Increase yield


Significant Positive Impact on Expansion Economics

($/bbl) ($ million)

Targeted Operating Cost per Barrel Targeted Operating Cost per Year

Note: Cost estimated with mine diesel and gas/energy as the major variable costs. No sustaining capital or major unplanned outage costs are included. 2014B cost per barrel reflects production lost downtime in 2014. Based on company internal forecast as at Nov 2013. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation.

0

500

1,000

1,500

2,000

2,500

2014B Phase 1 Phase 1-2-3

Fixed Variable

0

20

40

2014B Phase 1 Phase1-2-3

Fixed Variable


23

CNQ

Normalized Remaining NPV Profile

Horizon Delivers Sustainable Asset Value

Value of Long Life Assets

0.2

0.4

0.6

0.8

1

1.2

1.4

0 5 10 15 20 25 30 35 40 45

Horizon Phase 2/3 Light Oil Horizontal Multifrac's Typical SAGD

Note: Remaining NPV – reflects at any point in time the Net Present Value remaining for the project. Projects with long reserve lives have an NPV that

remains stable over time.


CNQ

Asset Summary

• Balanced high quality diverse asset base

• Vast long life, low decline resource base

• Sustainable, organic, profitable growth

• Unlocks significant value

• Delivers increasing and sustainable free cash flow



24

CNQ

$0

$1

$2

$3

$4

$5

$6

$7

2013F 2014B 2015F 2016F 2017F 2018F 2019F 2020F 2021F 2022F

Canadian Natural

Targeted Total Corporate Free Cash Flow


Free Cash Flow Growing to the Wall of Free Cash Flow

Note: Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. Free cash flow represents cash flow (cash flow net of corporate costs, interest, foreign exchange and taxes) less capital before dividends and share repurchases. Capital targeted between $7.0 and $7.8 billion for 2013F-2017F and significantly less thereafter. 2013F and 2014B based upon Nov. 7 guidance and budget numbers – see website for pricing assumptions. 2015F to 2017F based upon constant pricing assumptions forecasted at May 2013; WTI of US$94.95/bbl, AECO of C$3.50/GJ-C$4.00/GJ, and WCS differential of 26%. 2018F to 2022F based upon average strip pricing assumptions forecasted at May 2013; WTI of US$82.75/bbl, AECO of C$4.82/GJ, and WCS differential of 22%.

($ billion)

CNQ

Free Cash Flow Uses

1. Resource development

‒ Executing our defined plan

2. Dividends

‒ 14 consecutive years of dividend increases

31% CAGR (2009 – 2014)

‒ Must be sustainable

3. Share purchases


$28.91/share in 2012


$31.13/share YTD

4. Opportunistic acquisitions

5. Pay down debt




25

CNQ

2014 Targeted Free Cash Flow Uses


($ million) 2013F 2014B

Expected Cash Flow $ 7,640 $8,700

Capital Program 7,175 7,700

Free Cash Flow 465 1,000

Dividends $523 $870

Share Purchase* 300 ?

Flex Capital Program** - 0 - 400

Balance Sheet – (Build)/Draw $(358) $(270) - $130

Debt/Book 26.4% 25.4 - 26.2%

Debt/EBITDA 1.04x 1.0 - 1.05x

*Dependent on CNQ share price and commodity prices. **Dependent on construction market conditions at Horizon Projects. Note: Does not include any potential Montney land sale proceeds.

CNQ

Canadian Natural Advantage

• Strong, balanced assets deliver excess cash flow over near term

growth requirements

• Excess (free) cash flow allocation choices (competition)

‒ Increase asset strength and free cash flow

Resource development

Opportunistic acquisitions

‒Return to shareholders

Dividends

Share purchases

‒Balance sheet strength

Repay debt

• Effective and efficient operations

• Strong Management teams


Consistent History of Value Creation


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