2014 ANNUAL REPORT PREMIUM VALUE. DEFINED GROWTH. INDEPENDENT. 25079_CNR_2014_AR_001 | 285 Black | 24-MAR-1512:14:24 25079_CNR_2014_AR_BOOK.indb 1 15-03-12 6:20 PM TABLE OF CONTENTS 02 04 08 12 2014 Performance Highlights Letter to our Shareholders Our World-Class Team Year-End Reserves 20 Management’s Discussion and Analysis 56 Management’s Report 57 Management’s Assessment of Internal Control over Financial Reporting 58 60 Independent Auditor’s Report Consolidated Financial Statements 64 Notes to the Consolidated Financial Statements 92 Supplementary Oil and Gas Information 100 Ten-Year Review 102 Corporate Information VALUE CREATION For Canadian Natural, 2014 marked our twenty-fifth year in operations after restructuring to an exploration and production company in the oil and gas industry. The year also highlighted the Company’s strengths, which are predicated on a long-standing proven strategy and disciplined business approach. A strategy and business approach cultivated over our long history to maximize long-term value for shareholders. Canadian Natural achieved record annual average production of over 790,000 BOE/d in 2014. A significant accomplishment with crude oil and NGL assets producing at record levels of over 530,000 bbl/d and natural gas assets producing 1,555 MMcf/d. Our strong operations were supported by favorable economic factors and our disciplined financial approach. As a result, the Company realized approximately $9.6 billion of cash flow from operations in 2014, contributing to our strong financial position. The balance of our large and diverse asset base, our proven strategy and our balanced approach to capital allocation supports our transition to longer-life, low decline production. Canadian Natural is clearly in a very favorable position as we continue to execute our strategies and unlock significant value for shareholders. BALANCED PORTFOLIO Our proven business strategy is grounded by a belief in balance. We have built a large, diversified inventory of assets providing a balanced mix by segment, commodity type and production. The balance of our assets enables us to be flexible and nimble in response to changing business conditions. By employing a business approach that requires discipline and balance, we have the ability to weather industry cycles as we have options to reallocate capital, develop our asset base, make opportunistic acquisitions, repay debt or provide shareholder returns in the form of dividends or share purchases. 35 30 % 35 PRODUCTION MIX HEAVY CRUDE OIL & BITUMEN NATURAL GAS LIGHT CRUDE OIL, NGLs & SCO 25079_CNR_2014_AR_002_003 | 285 Black Cyan Magenta Yellow | 24-MAR-1512:14:28 25079_CNR_2014_AR_BOOK.indb 2 15-03-12 6:20 PM LARGE, BALANCED, HIGH QUALITY, DIVERSE ASSET BASE As at December 31, 2014, our Company Gross proved and probable reserves were 8.89 billion BOE, one of the largest reserve bases in the industry. Over the years we have built a tremendous resource base providing the foundation from which we derive our economic growth. Our diversified, balanced resource base consists of both dry and liquids-rich natural gas, heavy crude oil, bitumen, medium and light crude oil and synthetic crude oil, which allows us to allocate capital to the highest return projects and generate strong field operating free cash flow. LARGE ASSET BASE PRODUCTION (before royalties) PROVED RESERVES (1) PROVED PLUS PROBABLE RESERVES (1) 108 Mbbl/d 1,217 MMbbl (2) 2,312 MMbbl (2) 111 Mbbl/d 2,158 MMbbl (3) 3,593 MMbbl (3) 283 Mbbl/d 836 MMbbl 1,173 MMbbl 1,527 MMcf/d 5,869 Bcf 7,926 Bcf 12 Mbbl/d 21 MMcf/d 96 MMbbl 49 Bcf 149 MMbbl 98 Bcf 17 Mbbl/d 7 MMcf/d 204 MMbbl 83 Bcf 308 MMbbl 114 Bcf NORTHAMERICA OIL SANDS THERMAL IN SITU MINING & UPGRADING CRUDE OIL & NGLs NATURAL GAS OFFSHOREAFRICA CRUDE OIL & NGLs NATURAL GAS NORTH SEA CRUDE OIL & NGLs NATURAL GAS (1) Company Gross (2) Bitumen (3) Synthetic Crude Oil 25079_CNR_2014_AR_002_003 | 285 Black Cyan Magenta Yellow | 24-MAR-1512:14:28 25079_CNR_2014_AR_BOOK.indb 3 15-03-12 6:20 PM OUR FINANCIAL STRENGTH Throughout 2014, Canadian Natural continued to focus on maintaining a strong financial position. With clear financial objectives and a focus on cost control, we exited the year with debt to book capitalization of 33% and debt to EBITDA of 1.3 times. We proactively manage our debt and ensure that the financial community understands our business plans, our capital and our operating flexibility, and our ability to react quickly as business conditions warrant. The Company’s focus on managing a balanced financial program and generating strong cash flow helps to provide the appropriate financial resources for the near-, mid- and long-term. OUR TRANSITION TO A LONGER-LIFE, LOW DECLINE ASSET BASE Canadian Natural’s transformation to a longer-life, low decline asset base continued to take shape during 2014. In the third quarter, we expanded the Coker plant at Horizon Oil Sands (“Horizon”), which alleviated bottlenecks and added 12,000 bbl/d of synthetic crude oil productive capacity. Kirby South continued to progress toward 40,000 bbl/d of facility capacity, and Pelican Lake’s outstanding reservoir performance achieved annual record production success of over 50,000 bbl/d. At the end of 2014, over 50% of our crude oil and NGL production came from longer-life assets. By 2018, longer-life, low decline production will constitute more than 60% of overall crude oil and NGL production. Our transition will result in increasing, sustainable free cash flow generation for years to come. OUR SUSTAINABLE FREE CASH FLOW AND PROFITABLE GROWTH increase substantially over The Company generated $9.6 billion of cash flow from operations in 2014. As we transition our asset base to longer-life, low decline production, our sustainable free cash flow will the coming years. Fundamental to maintaining this sustainable free cash flow growth is our strategy of balance. Balance in our product mix, where we operate and our business approach enable us to execute on our defined growth plan, a key to unlocking the value of our large reserve and resource base. Debt to EBITDA Debt to Book Capitalization Bank Lines in Place Available Bank Lines Cash Flow from Operations* Per Common Share - basic - diluted Adjusted Earnings from Operations* Per Common Share - basic - diluted 1.3x 33% $ 5.6 million $ 2.6 million $ $ $ $ $ $ 9.6 billion 8.78 8.74 3.8 billion 3.49 3.47 *As defined on page 2 in the notes of the 2014 Performance Highlights. (% of CNQ liquids production)* 70% 60% 50% 40% 30% 20% 10% 0% 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 and 2018F based on company internal forecast as at March 2015 and November 2014 respectively. Dependent upon economic and regulatory conditions, commodity prices, global economic factors, project sanction and capital allocation. See forward-looking disclosures on page 20 of the Management’s Discussion and Analysis (“MD&A”). (C$ Billion) $8 $7 $6 $5 $4 $3 $2 $1 $0 -$1 -$2 34% CAGR 2014 reflecting acquisitions 2014 2015F 2016F 2017F 2018F US$90 WTI US$81 WTI US$70 WTI 2020F 2019F 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 purchases. CAGR represents 2014-2018F period. See page 19 and 20 for capital and pricing assumptions, and forward-looking disclosures. 25079_CNR_2014_AR_004_108 | Cyan Magenta Yellow Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 4 15-03-13 11:36 AM UNLOCKING SHAREHOLDER VALUE Canadian Natural is strong. We are well positioned to execute upon defined plans and deliver growing, sustainable free cash flow for years to come. As part of our proven strategy, we strive to economically grow production and effectively balance free cash flow allocation between resource development, opportunistic acquisitions, debt repayment, and returns to shareholders through dividends and share purchases. We strive to achieve safe, effective, efficient, and environmentally responsible operations of our diverse, balanced reserve base. This reserve base is one of the largest in the industry and will deliver strong free cash flow over the long term. Importantly, it also allows us to transition the Company to a long-life, low decline asset base that will substantially and sustainably increase free cash flow. At the same time, Canadian Natural continues to maintain a strong balance sheet with a capacity to capture opportunities and weather commodity price volatility. Most important of all, we have the people, the expertise, and the experience to execute our programs and operate effectively and efficiently. Canadian Natural is clearly in a very favorable position as we continue to execute our strategies and unlock significant value for shareholders. $0.90/SHARE 80% DECLARED IN 2014 DIVIDEND INCREASE IN 2014 UNLOCKING SHAREHOLDER VALUE Canadian Natural focuses on balanced and prudent capital allocation to maximize long-term value for shareholders. (C$ Million) 1,600 1,400 1,200 1,000 800 600 400 200 0 2002 44% CAGR Horizon Phase I build years 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 DIVIDEND SHARE PURCHASE Note: CAGR represents 2009-2014. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 1 25079_CNR_2014_AR_004_108 | Cyan Magenta Yellow Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 1 15-03-13 11:36 AM 2014 PERFORMANCE HIGHLIGHTS As the Company continues to progress the transition to a longer-life, low decline asset base, our balanced disciplined business approach generated record results in 2014. Canadian Natural achieved strong production and cash flow from operations, supported by our large, diverse asset base and dedicated teams. FINANCIAL ($ millions, except per common share amounts) Product sales Net earnings Per common share – basic – diluted Adjusted net earnings from operations (1) Per common share – basic – diluted Cash flow from operations (2) Per common share – basic – diluted Capital expenditures, net of dispositions Long-term debt (3) Shareholders’ equity OPERATING Daily production, before royalties Crude oil and NGLs (Mbbl/d) North America – excluding Oil Sands Mining and Upgrading North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Barrels of oil equivalent (MBOE/d) (4) 2014 2013 2012 $ $ $ $ $ $ $ $ $ $ $ $ $ 21,301 $ 3,929 $ 3.60 $ 3.58 $ 3,811 $ 3.49 $ 3.47 $ 9,587 $ 8.78 $ 8.74 $ 11,744 $ 14,002 $ 28,891 $ 17,945 $ 16,195 2,270 $ 1,892 2.08 $ 2.08 $ 1.72 1.72 2,435 $ 1,618 2.24 $ 2.23 $ 1.48 1.47 7,477 $ 6,013 6.87 $ 6.86 $ 5.48 5.47 7,274 $ 6,308 9,661 $ 25,772 $ 8,736 24,283 391 111 17 12 531 344 100 18 16 478 326 86 20 19 451 1,527 1,130 1,198 7 21 1,555 790 4 24 1,158 671 2 20 1,220 655 (1) Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation to this measure is discussed in the MD&A. (2) Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and repay debt. The derivation of this measure is discussed in the MD&A. Includes the current portion of long-term debt. (3) (4) 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. 2 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 2 15-03-12 6:20 PM Drilling activity (net wells) (1) North America North Sea Offshore Africa Core unproved property (thousands of net acres) North America North Sea Offshore Africa Company Gross proved plus probable reserves (2) Crude oil and NGLs (MMbbl) North America North Sea Offshore Africa Natural gas (Bcf) North America North Sea Offshore Africa Barrels of oil equivalent (MMBOE) (1) Excludes net stratigraphic test and service wells. (2) Year-end proved plus probable reserves were prepared using forecast prices and costs. 2014 2013 2012 1,112 1,190 1,271 5 - 1 - - - 1,117 1,191 1,271 20,583 93 2,467 23,143 14,672 110 2,467 17,249 13,775 128 4,307 18,210 7,078 308 149 7,535 7,926 114 98 8,138 8,891 6,495 325 153 6,973 5,881 125 103 6,109 7,991 6,431 332 158 6,921 5,574 102 111 5,787 7,886 COMPANY GROSS 2P RESERVES PER SHARE 413% 2P RESERVE REPLACEMENT RATIO 31YEARS 2P RESERVE LIFE INDEX (BOE) 9.00 8.00 7.00 6.00 5.00 4.00 3.00 2.00 1.00 0.00 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Note: Company Gross proved plus probable reserves prior to 2010 were prepared using constant prices and costs. Excludes Horizon SCO reserves prior to 2009. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Cyan Yellow Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 3 3 15-03-12 6:20 PM LETTER TO OUR SHAREHOLDERS 2014 marked our twenty-fifth year of oil and gas operations and in reflection, the year constituted a range of successful and challenging events. For Canadian Natural, we had a strong operating year, producing over 790 MBOE/d, we took the next step in our transition to longer-life, low decline assets with the completion of Phase 2A at Horizon, and we demonstrated our ability to allocate capital to value added acquisitions. As expected, heavy oil differentials narrowed during the year as a result of increased heavy crude oil demand and takeaway capacity. In late 2014, we saw pricing conditions in the crude oil market deteriorate. However, we were able to demonstrate that our strategy, with a balanced and disciplined business approach continues to prove successful in all cycles of the commodity business. Our balanced capital allocation approach included returns to shareholders through an increase of 80% in our dividend over the previous year and share purchases of 10,095,000 common shares at an aggregate cost of $453 million. Finally we continued to maintain a strong financial position, one that will help us weather fluctuations in the market and continue to deliver long-term value to our shareholders. SAFETY AND ENVIRONMENT At Canadian Natural, we make safety a core value, not just a priority. We know that priorities can change, but core values do not. Safety, reliability and efficiency are incorporated into our work; our concepts, designs, construction, operations, and decommissioning and reclamation activities. We remain committed to continued improvement safety performance with the ultimate goal of no harm to people and no unsafe incidents. From an environmental perspective, we’re focused on delivering proactive, environmentally responsible operations, where we continually drive to reduce our environmental footprint, and meet or exceed all regulatory requirements as well as our own internal targets. In 2015, the Company will continue to operate and execute with safety as a core value and remain proactive in delivering environmentally responsible operations. in our ADDING VALUE IN 2014 Our strategy is proven. Through the prudent development of our diverse asset base and our demonstrated ability to capture opportunities, we have consistently added value to our shareholders. We remain focused on balance. Balance provides us flexibility in our capital allocation choices and allows us to be effective and efficient in our operations. This flexibility equates to a strong financial position, providing us the ability to withstand downturns in economic conditions such as significant changes in commodity prices, while executing on value adding opportunities. In 2014, we continued to progress the transition of our portfolio to a longer-life, low decline asset base, while at the same time growing our asset base through opportunistic acquisitions. As at December 31, 2014, our proved plus probable reserves were 8.89 billion barrels of oil equivalent, one of the largest reserve bases in our industry. Our production mix remains balanced, drawing from our natural gas and crude oil assets. At the end of 2014, over 50% of our crude oil and NGL production came from longer-life assets. This continuing transition is less capital intensive, facilitating growth of sustainable free cash flow for many decades to come. We have the assets, the projects and the plan to deliver significant growth of long-life, low decline production going forward. NATURAL GAS Canadian Natural is the largest producer of natural gas in Canada. Supported by one of the largest land positions and significant infrastructure throughout Western Canada, our natural gas assets continue to be a strategic part of our production mix. Maintaining this strategic position and leveraging our experience enables us to maintain low operating costs in all pricing environments, ensuring we maximize returns for shareholders. In 2014 we increased the production from our natural gas assets through the successful completion of several opportunistic the continued development of our existing liquids-rich asset base. These activities supported year-over-year growth in natural gas acquisitions as well as 4 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 4 15-03-13 11:36 AM production of 34% from 2013 levels. In 2015 we target to preserve our land base through disciplined spending and will continue to develop our liquids-rich natural gas assets in Northeast BC and the Deep Basin. LIGHT CRUDE OIL AND NGLS NORTH AMERICA In 2014, we continued to increase our North America light crude oil and NGL production through a successful drilling program and the completion of certain opportunistic acquisitions. Through added production volumes and the use of technology such as horizontal multi-fracs and leveraging of our expertise, we were able to grow light crude oil and NGL production 31% over 2013 levels. In 2015, we will target multiple formations in a focused drilling program centered on delivering value. We will continue to optimize our existing improve operating costs and strengthen our operations, netbacks while maximizing value for our shareholders. INTERNATIONAL Our international offshore assets remain a strategic component of our balanced, diverse asset base. These assets offer exposure to international pricing, provide us offshore expertise and deliver significant cash flow that supports the Company’s transition to a longer-life, low decline asset base. Additionally these assets offer us offshore exploration upside such as our opportunities in Côte d’Ivoire and South Africa. is targeted for 2015. In Côte d’Ivoire, an exploration well on Block CI-514 was drilled in Q2/14 and encountered hydrocarbons; a second appraisal In South Africa, the operator well commenced drilling on our 50% interest in Block 11B/12B in Q3/14. The well was drilled to a sufficient depth to retain the exploratory right and the operator, along with Canadian Natural, In Offshore Africa, targets to re-enter the well development programs at both Espoir and Baobab are targeted to add economic production to the Company’s growth profile in 2015. in 2016. In the North Sea, previously announced Brownfield Allowance drilling continued in 2014 and successfully contributed to production increases. With other volume adding initiatives undertaken in the North Sea, including the reinstatement of the Banff/Kyle Floating Production Storage and Offloading vessel in Q3/14, these two programs target to increase production in the North Sea in 2015. 790 MBOE/D $9.6 BILLION PRODUCTION CASH FLOW FROM OPERATIONS zone recompletions HEAVY CRUDE OIL PRIMARY PRODUCTION Canadian Natural is the largest primary heavy crude oil producer in Canada, and our experienced teams and significant undeveloped land base continue to produce repeatable, proven performance. Our flexible and effective drilling programs deliver industry leading capital efficiencies and, along with low operating costs, provide strong netbacks and significant cash flow. In 2014, we achieved record average annual production in primary heavy crude oil of approximately 143,400 bbl/d, a 5% increase over 2013 levels. In 2015, primary heavy crude oil will continue to deliver economic production and significant free cash flow with our focused, flexible drilling program, well optimizations, and enhanced crude oil recovery opportunities. PELICAN LAKE Pelican Lake has one of the largest polymer floods in the world and is an important component in our transition to a longer-life, low decline asset base. At our leading edge polymer flood, the reservoir continues to respond positively with record annual production in 2014 averaging approximately 50,100 bbl/d, a 17% increase over 2013 levels. The technology driven polymer flood is targeted to require reduced reserves replacement capital as we target further increases in production in 2015 and beyond. This, along with our industry leading operating costs of less than $9.00/bbl will provide us with increasing free cash flow in the near-, mid- and long-term. A further testament to the success of our polymer flood and the value it generates for shareholders. MARKETING As the largest producer of heavy crude oil in Canada, Canadian Natural’s marketing strategy aims to maximize realized pricing and shareholder value through a three-pronged approach. We blend various crude oil streams and diluents to better serve the needs of our refining customers, we support the expansion of export pipeline capacity and finally, we support and participate in projects which add conversion capacity for heavy crude oil and bitumen. As expected, 2014 saw less volatility in the heavy crude oil differential. Supply and demand fundamentals became more balanced with additional heavy crude oil demand in the Chicago refining complex, increased takeaway capacity to the U.S. Gulf coast via the Flanagan South pipeline and the twinning of the Seaway pipeline. It is this balance that Canadian looks to leverage through its participation in the Natural Redwater refinery project. Canadian Natural owns 50% of the Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 5 5 15-03-12 6:20 PM HIGH QUALITY DIVERSIFIED PORTFOLIO EFFECTIVE AND EFFICIENT OPERATIONS DISCIPLINED BUSINESS APPROACH 50,000 bbl/d bitumen upgrader refinery project through its participation in the Redwater Partnership. The Redwater refinery is targeted to add bitumen conversion capacity in Alberta in 2017, contributing to improved heavy crude oil pricing, while generating a return to our shareholders. OIL SANDS THERMAL IN SITU 2014 was a year of continued execution and patience for the Company with regards to Primrose, our thermal in situ cyclic steam operations. At Primrose East, we filed our preliminary investigation report on the 2013 emulsions to surface with the regulator. With increased monitoring and modified steaming strategies in place, the regulator approved our steam flood application in Q3/14. In 2015, we will continue to steam flood approved areas and begin steaming under a low pressure cyclic steam process as proposed. At our Primrose North and South fields, we are able to employ cyclic pressure steaming, and the production response to our revised steaming strategies and increased monitoring has exceeded our expectations. Production at Primrose North and South was approximately 79,000 bbl/d, a 65% increase from 2013 levels. At Kirby South, the first of several of our large commercial steam assisted gravity drainage (“SAGD”) projects, thermal efficiencies are excellent as we ramp up to 40,000 bbl/d. Production in 2014 averaged approximately 15,200 bbl/d and we target to ramp up to facility capacity in the second half of 2015. Kirby South is a key part of our staged thermal in situ development plan and transformation to a longer-life, low decline asset base. Canadian Natural targets to increase thermal in situ facility capacity by 40,000 bbl/d to 60,000 bbl/d every 2 to 3 years to approximately 520,000 bbl/d, once economic conditions warrant investment. MINING AND UPGRADING At Horizon, the major component of our transition to a longer- life, low decline asset base, 2014 brought continued focus on safe, steady, and reliable production and a very meaningful improvement in plant performance.Through greater operational discipline and further reliability enhancements, the operations team at Horizon achieved an industry leading average utilization rate for the upgrader of 89%. With improved utilization, average annual production from this world class asset reached approximately 110,600 bbl/d of synthetic crude oil (“SCO”), a 10% increase over 2013 levels. Subsequent to the successful completion of Phase 2A in which additional coker capacity and equipment were added, the Horizon plant’s name plate capacity increased to 133,000 bbl/d. The strong performance of new equipment along with the implementation of an optimized mining strategy have enhanced the stability of the extraction and upgrading processes, increasing plant name capacity to 137,000 bbl/d. Consequently, production volumes following the commissioning of Phase 2A averaged approximately 136,000 bbl/d of SCO. further In 2015, we will continue to focus on operational discipline and safe, steady and reliable production. As a result of facility redundancy added during the Phase 2A completion, combined with our more effective mining strategy, less maintenance stress will be placed on the downstream equipment and overall performance of the Horizon plant will increase. This performance improvement has enabled us to reduce the scope of the 35 day maintenance turnaround to six days, targeted for the latter half of 2015. Remaining work is now targeted for May 2016. The shortened turnaround allows for an additional 10,000 bbl/d of SCO production in 2015, increasing our annual production guidance to range from 121,000 bbl/d to 131,000 bbl/d. We will also increase operating cost efficiencies through operations optimization and higher production volumes. Canadian Natural’s phased expansion strategy is working. The Phase 2A expansion added 12,000 bbl/d of SCO productive capacity, and at year end the entire Phase 2/3 project is now 56% physically complete. With approximately $6.0 billion targeted to be invested in aggregate over the next 3 years, the completion of the staged expansion to 250,000 bbl/d of productive capacity of SCO is in sight. We will now be able to complete the tie-in work for Phase 2B during the 2016 maintenance turnaround as a result of continued strong project execution and excellent construction performance of the Phase 2B expansion. Production volumes from Phase 2B are now targeted to incrementally increase earlier in 2016 than previously expected. After the May 2016 turnaround, volumes are expected to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the ramp up of the originally planned production levels. The completion of Phase 2B and Phase 3 will culminate in the addition of 45,000 bbl/d in late 2016 and 80,000 bbl/d of SCO productive capacity in late 2017. As the major component of our longer-life, low decline asset base, Horizon will generate significant free cash flow and value for our shareholders well into the future. 6 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 6 15-03-12 6:20 PM CANADIAN NATURAL’S STRATEGIC ADVANTAGE In 2014, we continued to add value for our shareholders through the ramp up of our Kirby South project and the completion and commissioning of Phase 2A at Horizon. These two elements are representative of our continued progression to a longer-life, low decline asset base, one that will yield growing, sustainable free cash flow for decades to come. Sustainable free cash flow that will support further resource development, a strong balance sheet, acquisition opportunities and returns to shareholders through share purchases and sustainable dividends. Today the industry is faced with crude oil pricing challenges that began in late 2014 and may persist until supply and demand can find an appropriate balance. Meanwhile, Canadian Natural is poised to withstand the uncertainties of today’s market. In 2015, we will continue to execute on our proven strategy and balanced business approach. We have built a large, diversified inventory of assets providing a balanced mix by segment, commodity type and production. This balanced production mix gives us the flexibility to allocate capital to the highest rate of return projects in our portfolio, whether it be a drilling opportunity, an opportunistic acquisition or to further strengthen our balance sheet. Our capital and operating flexibility, and the ability to react quickly to capture opportunities and withstand commodity price volatility are fundamental to the Company’s success in maximizing long- term shareholder value. The Company will continue to focus on maintaining a strong financial position as we continue to grow production. We have clear longstanding financial objectives designed to protect our balance sheet and maintain effective and efficient operations with a focus on cost control. We proactively manage our debt and ensure that the financial community understands our business plans, our capital and operating flexibility, and our ability to react quickly as business conditions warrant. This focus on effective and efficient operations facilitates favorable free cash flow generation during all commodity price cycles. A disciplined yet nimble and flexible financial approach to our operations ensures we are able to adapt quickly to changing conditions. As a result, the Company’s focus on managing a balanced financial program and generating strong cash flow helps to provide the appropriate financial resources for the near-, mid- and long-term. is well positioned to execute upon our Canadian Natural defined plans and deliver substantial and sustainable free cash flow for years to come. With our dedicated teams and committed, experienced management, and our adherence to safe and environmentally responsible operations, we will continue to strive to deliver long-term value for shareholders, effectively and efficiently. As a result, we will remain the premium value, defined growth independent. N. MURRAY EDWARDS Chairman STEVE W. LAUT President TIM S. MCKAY Chief Operating Officer DOUGLAS A. PROLL Executive Vice-President COREY B. BIEBER Chief Financial Officer & Senior Vice-President, Finance Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:44 25079_CNR_2014_AR_BOOK.indb 7 7 15-03-12 6:20 PM OUR WORLD-CLASS TEAM OUR PROVEN STRATEGY AND DISCIPLINED BUSINESS APPROACH ARE SUPPORTED BY OUR DEDICATED TEAMS AND EXPERIENCED MANAGEMENT TEAM. To develop people to work together to create value for the Company’s shareholders by doing it right with fun and integrity. G. Aalders, E. Aasen, A. Abadier, L. Abadier, Z. Abbas, T. Abbasi, D. Abbott, M. Abdeldayem, A. Abeda, M. Abeda, W. Abeda, A. Abeer, D. Abel, R. Abel, P. Abercrombie, R. Abrams, J. Abramyk, N. Abro, S. Abroskin, M. Abuelteen, C. Acharya, D. Acheson, J. Acosta, T. Adair, I. Adam, S. Adam, W. Adam, B. Adams, C. Adams, D. Adams, K. Adams, M. Adams, D. Adamson, C. Adan, R. Adan, D. Addinall, A. Adebayo, Y. Adebayo, B. Adeleye, M. Aden, A. Adesanya, M. Aditiakusuma, R. Adzabe Ella, J. Agate, A. Agnihotri, K. Agombar, I. Agu, U. Agu, A. Agustin, M. Ahmad, S. Ahmad, A. Ahmadi, M. Ahmadi, F. Ahmadloo, A. Ahmari, A. Ahmed, R. Ahmed, T. Aickelin, R. Aidoo, R. Aikens, G. Ailsby, K. Aitchison, K. Aitken, T. Ajayi, V. Akella, S. Akhtar, K. Akinde, A. Akinsanya, R. Akkineni, J. Akolkar, S. Akolkar, K. Akpan, D. Albert, J. Alcala, E. Alconcel, D. Alderdice, S. AlDhabbi, B. Alexander, D. Alexander, J. Alexander, P. Alexander, V. Alexander, E. Algazina, A. Ali, G. Ali, K. Ali, S. Ali, R. Aliazas, H. Aljanabi, M. Al-Kaisy, J. Allan, R. Allan, E. Allard, J. Allen, S. Allerton, D. Allibone, D. Allin, S. Allport, J. Allsop, N. Almasi, M. Almestar Bustamante, Y. Alnumi, A. Al- Saleem, R. Al-Samarrai, S. Al-Siani, A. Alstad, J. Alvarez, J. Alvarez Luzon, D. Amalaman, J. Aman, M. Amar, T. Amara, A. Amay, K. Amer, D. Ames, G. Amundrud, W. Amy, D. Andersen, T. Andersen, B. Anderson, C. Anderson, D. Anderson, G. Anderson, J. Anderson, K. Anderson, M. Anderson, N. Anderson, P. Anderson, W. Anderson, M. Andreas, P. Andrekson, C. Andres, J. Andres, D. Andrews, E. Andrews, L. Andrews, T. Andrews, C. Angeles, P. Angell, L. Angen, K. Angerman, N. Ango Mfene, C. Angus, M. Anis, E. Annis, S. Annis, P. Anongba, A. Ansell, D. Ansorger, R. Anstett, G. Anstey, L. Antal, J. Antle, K. Antonishyn, K. Antoniuk, T. Antoniuk, S. Antonuk, H. Aparicio Ramos, P. Appiah, B. April, R. April, J. Aquila, D. Aranas, R. Aranguren, F. Arano, D. Arberry, L. Arbour, C. Arcand, L. Archer, P. Archer, J. Argan, M. Arguin, H. Arias, L. Arias, J. 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Donald, S. Donaldson, R. Donaleshen, C. Dong, M. Dong, J. Donohoe, J. Donovan, N. Donovan, V. Dooling, J. Doonanco, T. Dootka, T. Doram, S. Dorer, A. Dorey, T. Dorgeles, S. Dorie, M. Dorocicz, J. Dorusak, A. Dosanjh, M. Doucet, R. Doucet, D. Doucette, K. Doucette, S. Douglas, A. Dowd, J. Dowd, S. Dowell, P. Downes, J. Downey, A. Downs, A. Doyer, R. Doyer, G. Doyle, L. Doyle, S. Drake, P. Drapeau, K. Draper, T. Draper, W. Draper, D. Draycott, K. Dreger, C. Drescher, D. Drescher, 8 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 8 15-03-12 6:20 PM D. Dressler, B. Drew, J. Dreyer, T. Dreyer, A. Drier, S. Driscoll, T. Driscoll, E. Drolet, C. Druhan, R. Drummond, C. Drury, S. Drysdall, V. D’Souza, M. Du, M. Du Preez, C. Duane, R. Duarte, M. Dube, N. Dube, T. Dube, D. Dubeau, J. Dubeau, S. Dubelt, T. Dubie, G. Dubois, J. Dubois, L. Dubuc, D. Duby, R. Ducharme, P. 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Krause, B. Krawchuk, C. Krawchuk, D. Krawec, H. Krawec, J. Krawetz, M. Krawetz, J. Kreft, T. Kreics, D. Krein, M. Kreiser, A. Krentz, D. Krentz, B. Kress, K. Krewulak, C. Kriaski, A. Krishnamoorthy, R. Krishnamurthy, N. Krochmal, D. Kroeger, R. Kroeker, K. Krogh, P. Krol, U. Krstic, R. Krueger, G. Kruger, N. Krupka, S. Kruse, K. Krynowsky, E. Krywolt, C. Kubik, J. Kubik, C. Kucinar, G. Kucy, E. Kudrynytskyi, A. Kuhn, M. Kulkarni, C. Kully, B. Kumar, R. Kumar, S. Kumar, V. Kumar, C. Kung, D. Kung, D. Kunitz, J. Kuntz, T. Kuntz, J. Kuo, 7,657 STRONG DIVERSITY.TALENT. EXPERTISE. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Cyan Magenta Yellow Black 285 | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 9 9 15-03-12 6:20 PM P. Kuppers, D. Kurek, M. Kureshi, K. Kurschenska, K. Kursteiner, D. Kurtz, R. Kurtz, F. Kurucz, J. Kushe, M. Kushneryk, I. Kushnir, B. Kutash, S. Kuzmak, C. Kwan, J. Kwan, K. Kwan, A. Kwiatkowski, K. 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Rabinovitch, B. Rabusic, D. Rach, A. Raciborski, D. Raciborski, W. Raczynski, L. Radesh, K. Radke, R. Radke, N. Radovanovic, M. Radu, R. Rae, I. Rafiyev, J. Rafter, G. Raghavan Nair, J. Raher, A. Rahmani, M. Rahmani, M. Rahmanian, P. Rai, Y. Raisbeck, I. Plesa, J. Plessis, L. Pletz, G. Plews, N. Plouffe, T. Plouffe, K. Plummer, 10 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Cyan Magenta Yellow Black 285 | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 10 15-03-12 6:20 PM M. Raisinghani, M. Raistrick, A. Raivio, J. Ramazani, D. Ramburrun, J. Ramirez, M. Ramirez, E. Ramirez Capitaine, C. Ramos, D. Ramsay, J. Ramsay, L. Ramsay, S. Ramsay, K. Ramsbottom, M. Rana, L. Rancourt, L. Randell, M. Randell, D. Rangen, J. Rankin, M. Rankin, D. Ranola, G. Ransom, J. Ransom, S. Rapin, S. Rasch, S. Rasheed, T. Rasheed, C. Rasko, S. Rasmussen, R. Raso, H. Rassi, W. Ratcliffe, S. Rathamone, A. Ratkevicius, S. Ratkovic, M. Rattray, H. 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Zwolak. 11 15-03-12 6:20 PM 25079_CNR_2014_AR_004_108 | Cyan Magenta Yellow Black 285 | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 11 YEAR-END RESERVES DETERMINATION OF RESERVES For the year ended December 31, 2014 the Company retained Independent Qualified Reserves Evaluators, Sproule Associates Limited, Sproule International Limited and GLJ Petroleum Consultants Ltd., to evaluate and review all of the Company’s proved and proved plus probable reserves. Sproule evaluated the Company’s North America and International crude oil, bitumen, natural gas and NGL reserves. GLJ evaluated the Company’s Horizon synthetic crude oil reserves. The Evaluators conducted the evaluation and review in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”). The reserves disclosure is presented in accordance with NI 51-101 requirements using forecast prices and escalated costs. The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with the Evaluators as to the Company’s reserves. All reserve values are Company Gross unless stated otherwise. CORPORATE TOTAL ■■ Proved crude oil, SCO, bitumen and NGL reserves increased 2% to 4.51 billion barrels. Proved natural gas reserves increased 39% to 6.00 Tcf. Total proved reserves increased 7% to 5.51 billion BOE. ■■ Proved plus probable crude oil, SCO, bitumen and NGL reserves increased 8% to 7.54 billion barrels. Proved plus probable natural gas reserves increased 33% to 8.14 Tcf. Total proved plus probable reserves increased 11% to 8.89 billion BOE. ■■ Proved reserve additions and revisions, including acquisitions, were 282 million barrels of crude oil, SCO, bitumen and NGL and 2,264 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio was 230%. The total proved BOE reserve life index is 19.0 years. ■■ Proved plus probable reserve additions and revisions, including acquisitions, were 753 million barrels of crude oil, bitumen, SCO and NGL and 2,597 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 413%. The total proved plus probable BOE reserve life index is 30.6 years. ■■ Proved undeveloped crude oil, SCO, bitumen and NGL reserves accounted for 27% of the corporate total proved reserves and proved undeveloped natural gas reserves accounted for 5% of the corporate total proved reserves. NORTH AMERICA EXPLORATION AND PRODUCTION ■■ Proved crude oil, bitumen and NGL reserves increased 9% to 2.05 billion barrels. Proved natural gas reserves increased 41% to 5.87 Tcf. Total proved BOE increased 18% to 3.03 billion barrels. ■■ Proved plus probable crude oil, bitumen and NGL reserves increased 9% to 3.49 billion barrels. Proved plus probable natural gas reserves increased 35% to 7.93 Tcf. Total proved plus probable BOE increased 15% to 4.81 billion barrels. ■■ Proved reserve additions and revisions, including acquisitions, were 308 million barrels of crude oil, bitumen and NGL and 2,266 billion cubic feet of natural gas. The total proved BOE reserve replacement ratio is 292%. The total proved BOE reserve life index in 13.1 years. ■■ Proved plus probable reserve additions and revisions, including acquisitions, were 420 million barrels of crude oil, bitumen and NGL and 2,602 billion cubic feet of natural gas. The total proved plus probable BOE reserve replacement ratio was 363%. The total proved plus probable BOE reserve life index is 20.7 years. ■■ Proved undeveloped crude oil, bitumen and NGL reserves accounted for 36% of the North America total proved reserves and proved undeveloped natural gas reserves accounted for 9% of the North America total proved reserves. ■■ Thermal oil sands (“bitumen”) proved reserves increased 5% to 1.22 billion barrels primarily due new proved undeveloped additions at Primrose and Wolf Lake. Proved reserve additions and revisions were 99 million barrels. Total proved plus probable bitumen reserves increased 7% to 2.31 billion barrels. NORTH AMERICA OIL SANDS MINING AND UPGRADING ■■ Proved plus probable SCO reserves increased 9% to 3.59 billion barrels, primarily due to a revised mine plan allowing mining to Total Volume : Bitumen In Place (“TV:BIP”) of 13 versus 12 in the original plan. INTERNATIONAL EXPLORATION AND PRODUCTION ■■ North Sea proved reserves decreased 9% to 218 million BOE. North Sea proved plus probable reserves decreased 5% to 327 million BOE. ■■ Offshore Africa proved reserves decreased 4% to 104 million BOE primarily due to production. Offshore Africa proved plus probable reserves decreased 3% to 165 million BOE. 12 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 12 15-03-12 6:20 PM SUMMARY OF COMPANY GROSS RESERVES As of December 31, 2014 Forecast Prices and Costs Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable North Sea Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Offshore Africa Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Total Company Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable 114 5 26 145 58 203 28 10 166 204 104 308 24 – 72 96 53 149 166 15 264 445 215 660 125 22 82 229 88 317 233 2 39 274 121 395 371 – 846 1,217 1,095 2,312 1,969 – 189 2,158 1,435 3,593 3,907 256 1,706 5,869 2,057 7,926 96 5 87 188 70 258 3,559 77 1,553 5,189 3,210 8,399 60 5 18 83 31 114 32 – 17 49 49 98 38 11 169 218 109 327 29 – 75 104 61 165 125 22 82 229 88 317 233 2 39 274 121 395 371 – 846 1,217 1,095 2,312 1,969 – 189 2,158 1,435 3,593 3,999 261 1,741 6,001 2,137 8,138 96 5 87 188 70 258 3,626 88 1,797 5,511 3,380 8,891 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 13 13 15-03-12 6:20 PM SUMMARY OF COMPANY NET RESERVES As of December 31, 2014 Forecast Prices and Costs Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable North Sea Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Offshore Africa Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable Total Company Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved plus Probable 99 4 23 126 48 174 28 10 166 204 104 308 21 – 57 78 41 119 148 14 246 408 193 601 105 18 69 192 69 261 176 1 29 206 82 288 281 – 668 949 838 1,787 1,609 – 155 1,764 1,139 2,903 3,436 215 1,403 5,054 1,737 6,791 71 4 68 143 53 196 2,913 63 1,246 4,222 2,519 6,741 60 5 18 83 31 114 23 – 13 36 32 68 38 11 169 218 109 327 25 – 59 84 46 130 105 18 69 192 69 261 176 1 29 206 82 288 281 – 668 949 838 1,787 1,609 – 155 1,764 1,139 2,903 3,519 220 1,434 5,173 1,800 6,973 71 4 68 143 53 196 2,976 74 1,474 4,524 2,674 7,198 14 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 14 15-03-12 6:20 PM RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2014 Forecast Prices and Costs Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) PROVED North America December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 North Sea December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Offshore Africa December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Total Company December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 117 1 7 3 – 31 (1) (1) 7 (19) 145 224 – – 1 – – – (16) 1 (6) 204 99 – – – – – – – 1 (4) 96 440 1 7 4 – 31 (1) (17) 9 (29) 445 244 – 29 12 – – – (1) (3) (52) 229 258 – – – – – – – 34 (18) 274 1,157 – 91 – – – – – 8 (39) 1,217 2,211 – – – – – – (4) (9) (40) 2,158 4,160 14 121 562 – 1,407 (1) (52) 215 (557) 5,869 110 1 5 32 – 34 – (1) 20 (13) 188 91 – – – – – – (6) 1 (3) 83 54 – – – – – – – 3 (8) 49 244 – 29 12 – – – (1) (3) (52) 229 258 – – – – – – – 34 (18) 274 1,157 – 91 – – – – – 8 (39) 1,217 2,211 – – – – – – (4) (9) (40) 2,158 4,305 14 121 562 – 1,407 (1) (58) 219 (568) 6,001 4,790 5 152 141 – 300 (1) (16) 94 (276) 5,189 239 – – 1 – – – (17) 2 (7) 218 108 – – – – – – – 1 (5) 104 110 1 5 32 – 34 – (1) 20 (13) 188 5,137 5 152 142 – 300 (1) (33) 97 (288) 5,511 15 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 15 15-03-12 6:20 PM RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2014 Forecast Prices and Costs PROBABLE North America December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 North Sea December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Offshore Africa December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Total Company December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 16 Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 49 1 5 3 – 9 – – (9) – 58 101 – – – – – – 13 (10) – 104 54 – – – – – – 1 (2) – 53 204 1 5 3 – 9 – 14 (21) – 215 90 – 12 4 – – – – (18) – 88 104 – – 1 – – – – 16 – 121 1,013 – 43 – – – – – 39 – 1,095 1,078 – 358 – – – – (7) 6 – 1,435 1,721 3 57 179 – 485 – 6 (394) – 2,057 64 – 3 11 – 13 – – (21) – 70 34 – – – – – – 2 (5) – 31 49 – – – – – – 1 (1) – 49 90 – 12 4 – – – – (18) – 88 104 – – 1 – – – – 16 – 121 1,013 – 43 – – – – – 39 – 1,095 1,078 – 358 – – – – (7) 6 – 1,435 1,804 3 57 179 – 485 – 9 (400) – 2,137 64 – 3 11 – 13 – – (21) – 70 2,685 1 431 49 – 103 – (5) (54) – 3,210 107 – – – – – – 13 (11) – 109 62 – – – – – – 1 (2) – 61 2,854 1 431 49 – 103 – 9 (67) – 3,380 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 16 15-03-12 6:20 PM RECONCILIATION OF COMPANY GROSS RESERVES As of December 31, 2014 Forecast Prices and Costs PROVED PLUS PROBABLE Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) North America December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 North Sea December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Offshore Africa December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Total Company December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 166 2 12 6 – 40 (1) (1) (2) (19) 203 325 – – 1 – – – (3) (9) (6) 308 153 – – – – – – 1 (1) (4) 149 644 2 12 7 – 40 (1) (3) (12) (29) 660 334 – 41 16 – – – (1) (21) (52) 317 362 – – 1 – – – – 50 (18) 395 2,170 – 134 – – – – – 47 (39) 2,312 3,289 – 358 – – – – (11) (3) (40) 3,593 334 – 41 16 – – – (1) (21) (52) 317 362 – – 1 – – – – 50 (18) 395 2,170 – 134 – – – – – 47 (39) 2,312 3,289 – 358 – – – – (11) (3) (40) 3,593 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 17 5,881 17 178 741 – 1,892 (1) (46) (179) (557) 7,926 125 – – – – – – (4) (4) (3) 114 103 – – – – – – 1 2 (8) 98 6,109 17 178 741 – 1,892 (1) (49) (181) (568) 8,138 174 1 8 43 – 47 – (1) (1) (13) 7,475 6 583 190 – 403 (1) (21) 40 (276) 258 8,399 346 – – 1 – – – (4) (9) (7) 327 170 – – – – – – 1 (1) (5) 165 7,991 6 583 191 – 403 (1) (24) 30 (288) 174 1 8 43 – 47 – (1) (1) (13) 258 8,891 17 15-03-12 6:20 PM NOTES REFERRING TO RESERVES TABLES: (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 reserve estimates were provided by Sproule Associates Limited: Crude oil and NGL WTI at Cushing (US$/bbl) Western Canada Select (C$/bbl) Canadian Light Sweet (C$/bbl) Edmonton Pentanes+ (C$/bbl) North Sea Brent (US$/bbl) Natural gas AECO (C$/MMBtu) BC Westcoast Station 2 (C$/MMBtu) Henry Hub Louisiana (US$/MMBtu) 2015 2016 2017 2018 2019 65.00 60.50 70.35 78.60 68.00 3.32 3.27 3.25 80.00 75.13 87.36 97.60 83.00 3.71 3.66 3.75 90.00 84.52 98.28 109.80 93.00 3.90 3.85 4.00 91.35 85.79 99.75 111.44 94.40 4.47 4.42 4.50 92.72 87.07 101.25 113.12 95.81 5.05 5.00 5.00 Average annual increase thereafter 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% 1.50% A foreign exchange rate of 0.8500 US$/C$ for 2015 and 0.8700 US$/C$ after 2015 was used in the 2014 evaluation. (5) Reserve additions and revisions are comprised of all categories of Company Gross reserve changes, exclusive of production. (6) Reserve replacement ratio is the Company Gross reserve additions and revisions divided by the Company Gross production in the same period. (7) 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. (8) Reserve Life Index is based on the amount for the relevant reserve category divided by the 2015 proved developed producing production forecast prepared by the Independent Qualified Reserve Evaluators. RESOURCE DISCLOSURE (1) Horizon Oil Sands Synthetic Crude Oil Discovered Bitumen Initially-in-place Proved Company Gross Reserves Bitumen volume associated with Proved SCO reserves Probable Company Gross Reserves Bitumen volume associated with Probable SCO reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) 2,158 million barrels of SCO 1,435 million barrels of SCO Bitumen (Thermal Oil) Discovered Bitumen Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Bitumen Produced to Date Unrecoverable portion of Discovered Bitumen Initially-in-place (2) Pelican Lake Heavy Crude Oil Pool 14,400 million barrels 2,540 million barrels of Bitumen 1,593 million barrels of Bitumen 3,693 million barrels of Bitumen 236 million barrels 6,338 million barrels 96,627 million barrels 1,217 million barrels of Bitumen 1,095 million barrels of Bitumen 8,491 million barrels of Bitumen 445 million barrels 85,380 million barrels Discovered Heavy Crude Oil Initially-in-place Proved Company Gross Reserves Probable Company Gross Reserves Best Estimate Contingent Resources other than Reserves Heavy Crude Oil Produced to Date Unrecoverable portion of Discovered Heavy Crude Oil Initially-in-place (2) 4,100 million barrels 274 million barrels of Heavy Crude Oil 121 million barrels of Heavy Crude Oil 153 million barrels of Heavy Crude Oil 215 million barrels 3,337 million barrels (1) All volumes are Company Gross. (2) A portion may be recoverable with the development of new technology. Note: Company gross proved and proved plus probable reserves at December 31, 2014. Produced to Date is cumulative production to December 31, 2014. Contingent Resources at December 31, 2014. 18 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 18 15-03-24 12:10 PM CAPITAL AND FREE CASH FLOW PRICING ASSUMPTIONS 1. 2015F reflects capital spending of $6.0 billion and the midpoint of guidance as of January 12th, 2015, and strip pricing as of February 2015. 2. 2016F to 2017F capital is targeted between $8.0 and $8.75 billion and less thereafter. 3. 2014 based upon actual; WTI of US$92.92/bbl, AECO of C$4.19/GJ, WCS differential of 21% and foreign exchange of US$1.00 to C$1.10. 4. 2015F based upon the midpoint of guidance as of January 12th, 2015, and pricing assumptions at February 2015; WTI of US$54.99/bbl, AECO of C$2.95/GJ, WCS differential of 27% and foreign exchange of US$1.00 to C$1.26. 5. 2016F to 2020F based on constant price assumptions of: WTI (US$) NYMEX (US$/MMbtu) AECO (C$/GJ) WCS differential FX (1 US$ = X C$) $70.00 WTI Strip $90.00 WTI $ $ $ $ 70.00 $ 3.75 $ 3.50 $ 22% 1.176 $ 81.00 $ 3.74 $ 3.45 $ 22% 1.126 $ 90.00 4.48 4.00 22% 1.11 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 19 19 15-03-12 6:20 PM MANAGEMENT’S DISCUSSION AND ANALYSIS SPECIAL NOTE REGARDING 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, operating costs, capital expenditures, income tax expenses and other guidance provided throughout this Management’s Discussion and Analysis (“MD&A”), 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 operations and future expansions, Primrose thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the 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, and the “Outlook” section of this MD&A, particularly in reference to the 2015 guidance provided with respect to production and budgeted capital expenditures, 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 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 20 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 20 15-03-12 6:20 PM 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 and Uncertainties” section of this MD&A. 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. SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES This MD&A includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings from operations, cash flow from operations, adjusted cash production costs and net asset value. These financial measures are not defined by International Financial Reporting Standards (“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 “Net Earnings and Cash Flow from Operations” section of this 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 this MD&A. The Company also presents certain non-GAAP financial ratios and their derivation in the “Liquidity and Capital Resources” section of this MD&A. MANAGEMENT’S DISCUSSION AND ANALYSIS This MD&A of the financial condition and results of operations of the Company should be read in conjunction with the Company’s audited consolidated financial statements and related notes for the year ended December 31, 2014. All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company’s consolidated financial statements and this MD&A have been prepared in accordance with IFRS as issued by the International Accounting Standards Board (“IASB”). 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 this 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 synthetic crude oil. Production volumes and per unit statistics are presented throughout this MD&A on a “before royalty” or “gross” basis, and realized prices are net of blending costs and exclude the effect of risk management activities. Production on an “after royalty” or “net” basis is also presented for information purposes only. The following discussion and analysis refers primarily to the Company’s 2014 financial results compared to 2013 and 2012, unless otherwise indicated. In addition, this MD&A details the Company’s capital program and outlook for 2015. Additional information relating to the Company, including its quarterly MD&A for the year and three months ended December 31, 2014, its Annual Information Form for the year ended December 31, 2014, and its audited consolidated financial statements for the year ended December 31, 2014 is available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. This MD&A is dated March 4, 2015. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 21 21 15-03-12 6:20 PM DEFINITIONS AND ABBREVIATIONS AECO AIF API ARO bbl bbl/d Bcf Bcf/d BOE BOE/d Bitumen Brent C$ CAGR CAPEX CO2 CO2e Crude oil CSS EOR E&P FPSO GHG GJ GJ/d Alberta natural gas reference location Annual Information Form specific gravity measured in degrees on the American Petroleum Institute scale asset retirement obligations LNG Mbbl Mbbl/d MBOE liquefied natural gas thousand barrels thousand barrels per day thousand barrels of oil equivalent MBOE/d thousand barrels of oil equivalent per day barrel barrels per day billion cubic feet billion cubic feet per day barrels of oil equivalent barrels of oil equivalent per day solid or semi-solid viscous mixture consisting mainly of pentanes and heavier hydrocarbons with viscosity greater than 10,000 centipoise Dated Brent Canadian dollars compound annual growth rate capital expenditures carbon dioxide carbon dioxide equivalents includes light and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic crude oil Cyclic Steam Stimulation Enhanced Oil Recovery Exploration and Production Mcf Mcf/d MMbbl MMBOE MMBtu MMcf MMcf/d MMcfe NGLs NYMEX NYSE PRT SAGD SCO SEC Tcf TSX UK US thousand cubic feet thousand cubic feet per day million barrels million barrels of oil equivalent million British thermal units million cubic feet million cubic feet per day millions of cubic feet equivalent natural gas liquids New York Mercantile Exchange New York Stock Exchange Petroleum Revenue Tax Steam-Assisted Gravity Drainage synthetic crude oil United States Securities and Exchange Commission trillion cubic feet Toronto Stock Exchange United Kingdom United States Floating Production, Storage and Offloading Vessel US GAAP generally accepted accounting principles in the United States greenhouse gas gigajoules gigajoules per day Horizon Horizon Oil Sands IASB IFRS LIBOR International Accounting Standards Board International Financial Reporting Standards London Interbank Offered Rate US$ WCS WCS Heavy Differential WTI United States dollars Western Canadian Select WCS Heavy Differential from WTI West Texas Intermediate reference location at Cushing, Oklahoma 22 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 22 15-03-12 6:20 PM OBJECTIVES AND STRATEGY The Company’s objectives are to increase crude oil and natural gas production, reserves, cash flow and net asset value (1) on a per common share basis through the development of its existing crude oil and natural gas properties and through the discovery and/or acquisition of new reserves. The Company strives to meet these objectives by having a defined growth and value enhancement plan for each of its products and segments while transitioning to a long life, low decline asset base.The Company takes a balanced approach to growth and investments and focuses on creating long-term shareholder value. The Company allocates its capital by maintaining: ■■ Balance among its products, namely light and medium crude oil and NGLs, Pelican Lake heavy crude oil (2), primary heavy crude oil, bitumen (thermal oil), SCO and natural gas; ■■ A large, balanced, diversified, high quality asset base; ■■ Balance among acquisitions, exploitation and exploration; and ■■ Balance between sources and terms of debt financing and a strong financial position. (1) Discounted value of crude oil and natural gas reserves plus value of unproved land, less net debt. (2) Pelican Lake heavy crude oil is 14–17º API oil, which receives medium quality crude netbacks due to lower production costs and lower royalty rates. The Company’s three-phase crude oil marketing strategy includes: ■■ Blending various crude oil streams with diluents to create more attractive feedstock; ■■ Supporting and participating in pipeline expansions and/or new additions; and ■■ Supporting and participating in projects that will increase the downstream conversion capacity for heavy crude oil and bitumen (thermal oil). Operational discipline, safe, effective and efficient operations as well as cost control are fundamental to the Company. By consistently managing costs throughout all cycles of the industry, the Company believes it will achieve continued growth. Effective and efficient operations and cost control are attained by developing area knowledge, and by maintaining high working interests and operator status in its properties. The Company is committed to maintaining a strong balance sheet and flexible capital structure.The Company believes it has built the necessary financial capacity to complete its growth projects. Additionally, the Company’s risk management hedging program reduces the risk of volatility in commodity prices and supports the Company’s cash flow for its capital expenditure programs. Strategic accretive acquisitions are a key component of the Company’s strategy. The Company has used a combination of internally generated cash flows and debt financing to selectively acquire properties generating future cash flows in its core areas. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:45 25079_CNR_2014_AR_BOOK.indb 23 23 15-03-12 6:20 PM NET EARNINGS AND CASH FLOW FROM OPERATIONS FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) Product sales Net earnings Per common share – basic – diluted Adjusted net earnings from operations (1) Per common share – basic – diluted Cash flow from operations (2) Per common share – basic – diluted Dividends declared per common share (3) Total assets Total long-term liabilities Capital expenditures, net of dispositions 2014 21,301 $ 3,929 $ 3.60 $ 3.58 $ 3,811 $ 3.49 $ 3.47 $ 9,587 $ 8.78 $ 8.74 $ 0.90 $ 60,200 $ 26,167 $ 11,744 $ 2013 17,945 $ 2,270 $ 2.08 $ 2.08 $ 2,435 $ 2.24 $ 2.23 $ 7,477 $ 6.87 $ 6.86 $ 0.575 $ 51,754 $ 20,748 $ 7,274 $ 2012 16,195 1,892 1.72 1.72 1,618 1.48 1.47 6,013 5.48 5.47 0.42 48,980 20,721 6,308 $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” 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. (2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments.The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations” presents certain non-cash items that are included in the Company’s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies. (3) On March 5, 2014, the Board of Directors approved a quarterly dividend of $0.225 per common share, beginning with the dividend payable on April 1, 2014. In 2013, the Board of Directors approved a dividend of $0.20 per common share on November 5, 2013, beginning with the dividend payable on January 1, 2014 ($0.125 per common share, approved on March 6, 2013, beginning with the dividend payable on April 1, 2013). In 2012, the Board of Directors approved a quarterly dividend of $0.105 per common share, beginning with the dividend payable on April 1, 2012. Adjusted Net Earnings from Operations ($ millions) Net earnings as reported Share-based compensation expense (recovery), net of tax (1) Unrealized risk management (gain) loss, net of tax (2) Unrealized foreign exchange loss, net of tax (3) Realized foreign exchange loss (gain) on repayment of US dollar debt securities, net of tax (4) Gain on corporate acquisitions/disposition of properties, net of tax (5) Effect of statutory tax rate and other legislative changes on deferred income tax liabilities (6) Adjusted net earnings from operations 2014 2013 $ 3,929 $ 2,270 $ 66 (339) 256 36 (137) 135 32 226 (12) (231) 2012 1,892 (214) (37) 129 (210) – – 3,811 $ 15 2,435 $ 58 1,618 $ (1) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs. (2) Derivative financial instruments are recorded at fair value on the Company’s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas. (3) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings. (4) During 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. During 2013, the Company repaid US$400 million of 5.15% notes. During 2012, the Company repaid US$350 million of 5.45% notes. (5) During 2014, the Company recorded an after-tax gain of $137 million related to the acquisition of certain producing crude oil and natural gas properties. During 2013, the Company recorded an after-tax gain of $231 million related to the acquisition of Barrick Energy Inc. and the disposition of a 50% interest in an exploration right in South Africa. (6) All substantively enacted adjustments in applicable income tax rates and other legislative changes are applied to underlying assets and liabilities on the Company’s balance sheets in determining deferred income tax assets and liabilities. The impact of these tax rate and other legislative changes is recorded in net earnings during the period the legislation is substantively enacted. During 2013, the Government of British Columbia substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013, resulting in an increase in the Company’s deferred income tax liability of $15 million. During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax rate relief on UK North Sea decommissioning expenditures to 50%, resulting in an increase in the Company’s deferred income tax liability of $58 million. 24 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 24 15-03-12 6:20 PM Cash Flow from Operations ($ millions) Net earnings Non-cash items: Depletion, depreciation and amortization Share-based compensation Asset retirement obligation accretion Unrealized risk management (gain) loss Unrealized foreign exchange loss Realized foreign exchange loss (gain) on repayment of US dollar debt securities Equity loss from investment Deferred income tax expense (recovery) Gain on corporate acquisitions/disposition of properties Current income tax on disposition of properties Cash flow from operations 2014 2013 $ 3,929 $ 2,270 $ 2012 1,892 4,880 4,844 4,328 66 193 (451) 256 36 8 807 (137) – 135 171 39 226 (12) 4 31 (289) 58 (214) 151 (42) 129 (210) 9 (30) – – $ 9,587 $ 7,477 $ 6,013 For 2014, the Company reported net earnings of $3,929 million compared with net earnings of $2,270 million for 2013 (2012 – $1,892 million). Net earnings for 2014 included net after-tax income of $118 million related to the effects of share-based compensation, risk management activities, fluctuations in foreign exchange rates including the impact of realized foreign exchange losses and gains on repayments of long-term debt, gains on corporate acquisitions/disposition of properties, and the impact of statutory tax rate and other legislative changes on deferred income tax liabilities (2013 – $165 million after-tax expenses; 2012 – $274 million after-tax income). Excluding these items, adjusted net earnings from operations for 2014 were $3,811 million compared with $2,435 million for 2013 (2012 – $1,618 million). The increase in adjusted net earnings for 2014 from the comparable period in 2013 was primarily due to: ■■ higher crude oil and NGLs, natural gas, and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments; ■■ higher crude oil and NGLs and natural gas netbacks in the North America segment; ■■ higher realized risk management gains; and ■■ the impact of a weaker Canadian dollar relative to the US dollar; partially offset by: ■■ ■■ lower crude oil sales volumes in the Offshore Africa segment; and lower crude oil netbacks in the North Sea and Offshore Africa segments. The impacts of share-based compensation, risk management activities and fluctuations in foreign exchange rates are expected to continue to contribute to significant volatility in consolidated net earnings and are discussed in detail in the relevant sections of this MD&A. Cash flow from operations for 2014 increased to $9,587 million ($8.78 per common share) from $7,477 million for 2013 ($6.87 per common share) (2012 – $6,013 million; $5.48 per common share). The increase in cash flow from operations for 2014 from 2013 was primarily due to the factors noted above relating to the increase in adjusted net earnings, together with the impact of lower cash taxes. In the Company’s Exploration and Production activities, the 2014 average sales price per bbl of crude oil and NGLs increased 4% to average $77.04 per bbl from $73.81 per bbl in 2013 (2012 – $72.44 per bbl), and the 2014 average natural gas price increased 35% to average $4.83 per Mcf from $3.58 per Mcf in 2013 (2012 – $2.70 per Mcf). In the Oil Sands Mining and Upgrading segment, the Company’s 2014 sales price of SCO averaged $100.27 per bbl, compared with $100.75 per bbl in 2013 (2012 – $90.74 per bbl). Total production of crude oil and NGLs before royalties increased 11% to 531,194 bbl/d from 478,240 bbl/d in 2013 (2012 – 451,378 bbl/d). The increase in crude oil and NGLs production from 2013 was due to higher production in the North America segment and strong and reliable production in Horizon. Total natural gas production before royalties increased 34% to average 1,555 MMcf/d from 1,158 MMcf/d in 2013 (2012 – 1,220 MMcf/d). The increase in natural gas production was primarily a result of the acquisitions of producing Canadian natural gas properties in 2014, and the completion of the Septimus drilling program and plant facility expansion in 2013. Total crude oil and NGLs and natural gas production volumes before royalties increased 18% to average 790,410 BOE/d from 671,162 BOE/d in 2013 (2012 – 654,665 BOE/d). Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 25 25 15-03-12 6:20 PM SUMMARY OF QUARTERLY RESULTS The following is a summary of the Company’s quarterly results for the eight most recently completed quarters: ($ millions, except per common share amounts) 2014 Product sales Net earnings Net earnings per common share – basic – diluted 2013 Product sales Net earnings Net earnings per common share – basic – diluted Total Dec 31 Sep 30 Jun 30 Mar 31 21,301 $ 4,850 $ 5,370 $ 6,113 $ 4,968 3,929 $ 1,198 $ 1,039 $ 1,070 $ 622 3.60 $ 3.58 $ 1.10 $ 1.09 $ 0.95 $ 0.94 $ 0.98 $ 0.97 $ 0.57 0.57 Total 17,945 $ 2,270 $ Dec 31 Sep 30 4,330 $ 5,284 $ Jun 30 4,230 $ Mar 31 4,101 413 $ 1,168 $ 476 $ 213 2.08 $ 2.08 $ 0.38 $ 0.38 $ 1.07 $ 1.07 $ 0.44 $ 0.44 $ 0.19 0.19 $ $ $ $ $ $ $ $ Volatility in the quarterly net earnings over the eight most recently completed quarters was primarily due to: ■■ Crude oil pricing – The impact of fluctuating demand, inventory storage levels, increased shale oil production in North America, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from WTI in North America and the impact of the differential between WTI and Brent benchmark pricing in the North Sea and Offshore Africa. ■■ Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US. ■■ Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the strong heavy crude oil drilling program, the impact and timing of acquisitions, and the impact of turnarounds at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa. ■■ Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude oil projects, as well as natural decline rates, shut-in natural gas production due to pricing and the impact and timing of acquisitions. ■■ Production expense – Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix and production, the impact of seasonal costs that are dependent on weather, cost optimizations in North America, the impact and timing of acquisitions, and turnarounds at Horizon. ■■ Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, fluctuations in depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison platform, and the impact of turnarounds at Horizon. ■■ Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company’s share-based compensation liability. ■■ Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities. ■■ Foreign exchange rates – Changes in the Canadian dollar relative to the US dollar, which impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominantly on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges. ■■ Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods. ■■ Gains on corporate acquisitions/disposition of properties – Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the fourth quarter of 2014 and the third quarter of 2013. 26 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 26 15-03-12 6:20 PM BUSINESS ENVIRONMENT (Yearly average) WTI benchmark price (US$/bbl) Dated Brent benchmark price (US$/bbl) WCS blend differential from WTI (US$/bbl) WCS blend differential from WTI (%) SCO price (US$/bbl) Condensate benchmark price (US$/bbl) NYMEX benchmark price (US$/MMBtu) AECO benchmark price (C$/GJ) US / Canadian dollar average exchange rate (US$) US / Canadian dollar year end exchange rate (US$) 2014 2013 92.92 $ 98.00 $ 98.85 $ 108.62 $ 19.41 $ 25.11 $ 21% 26% 91.35 $ 98.18 $ 2012 94.19 111.56 21.05 22% 92.59 92.84 $ 101.67 $ 100.92 4.37 $ 4.19 $ 3.67 $ 3.00 $ 0.9054 $ 0.9710 $ 0.8620 $ 0.9402 $ 2.80 2.28 1.0004 1.0051 $ $ $ $ $ $ $ $ $ Substantially all of the Company’s production is sold based on US dollar benchmark pricing. Specifically, crude oil is marketed based on WTI and Brent indices. Canadian natural gas pricing is primarily based on Alberta AECO reference pricing, which is derived from the NYMEX reference pricing and adjusted for its basis or location differential to the NYMEX delivery point at Henry Hub. The Company’s realized prices are also highly sensitive to fluctuations in foreign exchange rates. Realized prices in 2014 were impacted by the weaker Canadian dollar, which increased the Canadian dollar sales price the Company received for its crude oil and natural gas sales as realized pricing is based on US dollar denominated benchmarks. The average value of the Canadian dollar in relation to the US dollar fluctuated significantly throughout 2014, with a high of approximately US$0.94 in January 2014 and a low of approximately US$0.86 in December 2014. Crude oil sales contracts in the North America segment are typically based on WTI benchmark pricing. For 2014, WTI averaged US$92.92 per bbl, a decrease of 5% from US$98.00 per bbl for 2013 (2012 – US$94.19 per bbl). Crude oil sales contracts for the Company’s North Sea and Offshore Africa segments are typically based on Brent pricing, which is representative of international markets and overall world supply and demand. Brent averaged US$98.85 per bbl for 2014, a decrease of 9% from US$108.62 per bbl for 2013 (2012 – US$111.56 per bbl). WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. An oversupply in the world market contributed to a significant decrease in crude oil benchmark pricing in the fourth quarter of 2014. The Organization of the Petroleum Exporting Countries’ (“OPEC”) decision in November 2014 to not reduce crude oil production to offset the excess world supply continues to put downward pressure on benchmark pricing. In January 2015, WTI averaged US$47.33 per bbl and Brent averaged US$48.07 per bbl and in February, WTI averaged US$50.72 per bbl and Brent averaged US$57.93 per bbl. The Brent differential from WTI tightened for 2014 from 2013 due to continued debottlenecking of logistical constraints from Cushing to the US Gulf Coast in the first half of 2014. The WCS Heavy Differential averaged 21% for 2014 compared with 26% for 2013 (2012 – 22%). The WCS Heavy Differential tightened from the comparable period in 2013 as the comparable period in 2013 reflected lower heavy oil demand due to unplanned refinery disruptions and pipeline logistical constraints. In January 2015, the WCS Heavy Differential averaged US$16.90 per bbl or 36% and in February 2015, the WCS Heavy Differential averaged US$14.20 per bbl or 28%. To partially mitigate its exposure to fluctuating heavy crude oil differentials, the Company entered into 30,000 bbl/d of crude oil WCS differential swaps for the first quarter of 2015 at weighted average fixed WCS differential of US$21.49 per bbl. The WCS Heavy Differential is expected to continue to reflect seasonal demand fluctuations, changes in transportation logistics, and refinery utilization and shutdowns. The SCO price averaged US$91.35 per bbl in 2014, a decrease of 7% from US$98.18 per bbl for 2013 (2012 – US$92.59 per bbl). The decrease in SCO pricing was primarily due to a decrease in WTI benchmark pricing. NYMEX natural gas prices averaged US$4.37 per MMBtu for 2014, an increase of 19% from US$3.67 per MMBtu for 2013 (2012 – US$2.80 per MMBtu). AECO natural gas pricing averaged $4.19 per GJ for 2014, an increase of 40% from $3.00 per GJ for 2013 (2012 – $2.28 per GJ). The higher natural gas pricing in 2014 was primarily due to the drawdown of natural gas storage inventories as a result of the colder than normal winter temperatures in the first quarter of 2014. Growing US shale gas production resulted in natural gas inventories returning to normal industry levels by the end of 2014, leading to downward pressure on prices. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 27 27 15-03-12 6:20 PM ANALYSIS OF CHANGES IN PRODUCT SALES ($ millions) 2012 Volumes Prices Other 2013 Volumes Prices Other 2014 Changes due to Changes due to North America Crude oil and NGLs $ 10,480 $ 501 $ 319 $ (54) $ 11,246 $ 1,527 $ 585 $ (26) $ 13,332 Natural gas North Sea Crude oil and NGLs Natural gas Offshore Africa Crude oil and NGLs Natural gas Subtotal Crude oil and NGLs Natural gas Oil Sands Mining and Upgrading Midstream Intersegment eliminations and other (1) 1,127 11,607 924 4 928 699 74 773 12,103 1,205 13,308 2,871 93 (67) 434 (121) 4 (117) 38 15 53 418 (48) 370 399 – 353 672 – 1,413 (54) 12,659 497 2,024 721 1,306 – 2,631 (26) 15,963 4 2 6 (7) 2 (5) 316 357 673 361 – (12) – (12) 3 – 3 (63) – (63) – 17 795 10 805 733 91 824 12,774 1,514 14,288 3,631 110 (3) 8 5 (264) (10) (274) 1,260 495 1,755 463 – (37) 1 (36) (52) 12 (40) (73) – (73) (7) – (7) 682 19 701 410 93 503 496 734 1,230 (106) – (106) 14,424 2,743 17,167 (20) – 21 10 4,095 120 (77) – – (7) (84) – – 3 (81) Total $ 16,195 $ 769 $ 1,034 $ (53) $ 17,945 $ 2,218 $ 1,210 $ (72) $ 21,301 (1) Eliminates internal transportation, electricity charges, and natural gas sales. Product sales increased 19% to $21,301 million for 2014 from $17,945 million for 2013 (2012 – $16,195 million). The increase was primarily due to higher crude oil and NGLs, natural gas, and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments and an increase in realized North America crude oil and NGLs and natural gas prices. For 2014, 6% of the Company’s crude oil and NGLs and natural gas product sales were generated outside of North America (2013 – 9%; 2012 – 11%). North Sea accounted for 3% of crude oil and NGLs and natural gas product sales for 2014 (2013 – 4%; 2012 – 6%), and Offshore Africa accounted for 3% of crude oil and NGLs and natural gas product sales for 2014 (2013 – 5%; 2012 – 5%). 28 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 28 15-03-12 6:20 PM ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (1) North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total barrels of oil equivalent (BOE/d) Product mix Light and medium crude oil and NGLs Pelican Lake heavy crude oil Primary heavy crude oil Bitumen (thermal oil) Synthetic crude oil (1) Natural gas Percentage of gross revenue (1) (2) (excluding Midstream revenue) Crude oil and NGLs Natural gas 2014 2013 2012 390,814 110,571 17,380 12,429 531,194 1,527 7 21 1,555 343,699 100,284 18,334 15,923 478,240 1,130 4 24 1,158 326,829 86,077 19,824 18,648 451,378 1,198 2 20 1,220 790,410 671,162 654,665 15% 6% 18% 14% 14% 33% 85% 15% 15% 7% 20% 14% 15% 29% 90% 10% 16% 6% 19% 15% 13% 31% 91% 9% (1) The Company commenced production of diesel for internal use at Horizon in the third quarter of 2014. 2014 SCO production before royalties excludes 545 bbl/d of SCO consumed internally as diesel. (2) Net of blending costs and excluding risk management activities. ANALYSIS OF DAILY PRODUCTION, NET OF ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (1) North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total barrels of oil equivalent (BOE/d) 2014 2013 2012 318,291 104,095 17,313 11,500 451,199 1,407 7 18 1,432 689,893 287,428 95,098 18,279 12,973 413,778 1,080 4 20 1,104 597,835 273,374 82,171 19,772 13,628 388,945 1,171 2 17 1,190 587,246 (1) The Company commenced production of diesel for internal use at Horizon in the third quarter of 2014. 2014 SCO production before royalties excludes 545 bbl/d of SCO consumed internally as diesel. The Company’s business approach is to maintain large project inventories and production diversification among each of the commodities it produces; namely light and medium crude oil and NGLs, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), SCO and natural gas. Total 2014 production averaged 790,410 BOE/d, an 18% increase from 671,162 BOE/d in 2013 (2012 – 654,665 BOE/d). Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 29 29 15-03-12 6:20 PM Total production of crude oil and NGLs before royalties increased 11% to 531,194 bbl/d for 2014 from 478,240 bbl/d in 2013 (2012 – 451,378 bbl/d). The increase in crude oil and NGLs production from 2013 was primarily due to higher production in the North America segment and strong and reliable production in Horizon. Crude oil and NGLs production for 2014 was within the Company’s previously issued guidance of 531,000 to 557,000 bbl/d. Natural gas production continued to represent the Company’s largest product offering, accounting for 33% of the Company’s total production in 2014 on a BOE basis. Total natural gas production before royalties increased 34% to 1,555 MMcf/d for 2014 from 1,158 MMcf/d for 2013 (2012 – 1,220 MMcf/d). The increase in natural gas production from 2013 was primarily a result of the acquisitions of producing Canadian natural gas properties in 2014, and the completion of the Septimus drilling program and plant facility expansion. Natural gas production for 2014 was within the Company’s previously issued guidance of 1,550 to 1,570 MMcf/d. NORTH AMERICA – EXPLORATION AND PRODUCTION North America crude oil and NGLs production for 2014 increased 14% to average 390,814 bbl/d from 343,699 bbl/d for 2013 (2012 – 326,829 bbl/d).The increase in production from 2013 was primarily due to increased production related to the acquisitions of producing Canadian crude oil properties in 2014, production at the Company’s thermal areas including Kirby South, the impact of the heavy crude oil drilling program, and the ramp up of production at Pelican Lake. North America natural gas production for 2014 increased 35% to average 1,527 MMcf/d from 1,130 MMcf/d in 2013 (2012 – 1,198 MMcf/d). The increase in natural gas production from 2013 was primarily a result of the acquisitions of producing Canadian natural gas properties in 2014, and the completion of the Septimus drilling program and plant facility expansion. NORTH AMERICA – OIL SANDS MINING AND UPGRADING Production for 2014 increased 10% to average 110,571 bbl/d compared with 100,284 bbl/d for 2013 (2012 – 86,077 bbl/d). Production in 2014 increased from 2013 due to increased plant reliability and the successful completion of the coker plant expansion in 2014. NORTH SEA North Sea crude oil production for 2014 was 17,380 bbl/d, a decrease of 5% from 18,334 bbl/d for 2013 (2012 – 19,824 bbl/d). Production in 2014 reflected the impact of reinstatement of production from the Banff FPSO in July 2014, which had been offline since December 2011 after suffering storm damage. Production in 2014 also reflected the cessation of production due to the planned early decommissioning of the Murchison platform which commenced in 2013, unplanned downtime on the Tiffany platform, and natural field declines. OFFSHORE AFRICA Offshore Africa crude oil production for 2014 decreased 22% to 12,429 bbl/d from 15,923 bbl/d for 2013 (2012 – 18,648 bbl/d) primarily due to natural field declines. CORPORATE PRODUCTION GUIDANCE FOR 2015 The Company targets production levels in 2015 to average between 562,000 bbl/d and 602,000 bbl/d of crude oil and NGLs and between 1,730 MMcf/d and 1,770 MMcf/d of natural gas. CRUDE OIL INVENTORY VOLUMES The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. Revenue has not been recognized on crude oil volumes that were stored in various tanks, pipelines, or FPSOs, as follows: (bbl) North America – Exploration and Production North America – Oil Sands Mining and Upgrading (SCO) North Sea Offshore Africa 2014 2013 2012 930,116 1,266,063 368,808 461,997 3,026,984 830,673 1,550,857 385,073 185,476 2,952,079 643,758 993,627 77,018 1,036,509 2,750,912 30 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 30 15-03-12 6:20 PM OPERATING HIGHLIGHTS – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Natural gas ($/Mcf) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Barrels of oil equivalent ($/BOE) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. ANALYSIS OF PRODUCT PRICES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) (2) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) (2) North America North Sea Offshore Africa Company average Company average ($/BOE) (1) (2) 2014 2013 2012 77.04 $ 73.81 $ 2.41 74.63 12.99 18.25 43.39 $ 2.22 71.59 11.13 17.14 43.32 $ 4.83 $ 3.58 $ 0.27 4.56 0.38 1.48 2.70 $ 0.28 3.30 0.18 1.42 1.70 $ 58.48 $ 56.46 $ 2.18 56.30 8.90 14.67 32.73 $ 2.10 54.36 7.74 14.24 32.38 $ 72.44 2.20 70.24 10.67 16.11 43.46 2.70 0.26 2.44 0.09 1.31 1.04 52.85 2.04 50.81 7.07 13.14 30.60 2014 2013 2012 75.09 $ 106.63 $ 97.81 $ 77.04 $ 4.72 $ 7.07 $ 11.98 $ 4.83 $ 58.48 $ 69.90 $ 112.46 $ 110.21 $ 73.81 $ 3.43 $ 5.69 $ 10.45 $ 3.58 $ 56.46 $ 67.93 111.90 111.18 72.44 2.57 5.14 10.31 2.70 52.85 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. Realized crude oil and NGLs prices increased 4% to average $77.04 per bbl for 2014 from $73.81 per bbl for 2013 (2012 – $72.44 per bbl). The increase in 2014 was primarily due to tightening WCS Heavy Differentials and the impact of a weakening Canadian dollar, partially offset by lower benchmark pricing. The Company’s realized natural gas price increased 35% to average $4.83 per Mcf for 2014 from $3.58 per Mcf for 2013 (2012 – $2.70 per Mcf). The increase in 2014 was due to the drawdown of natural gas storage inventories as a result of colder than normal winter temperatures in 2014. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 31 31 15-03-12 6:20 PM NORTH AMERICA North America realized crude oil prices increased 7% to average $75.09 per bbl for 2014 from $69.90 per bbl for 2013 (2012 – $67.93 per bbl), primarily due to tightening WCS Heavy Differentials and the impact of a weakening Canadian dollar, partially offset by lower WTI benchmark pricing. North America realized natural gas prices increased 38% to average $4.72 per Mcf for 2014 from $3.43 per Mcf for 2013 (2012 – $2.57 per Mcf), due to the drawdown of natural gas storage inventories as a result of colder than normal winter temperatures in the first quarter of 2014. The Company continues to focus on its crude oil marketing strategy including a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with refiners to add incremental heavy crude oil and bitumen (thermal oil) conversion capacity. During 2014, the Company contributed approximately 167,000 bbl/d of heavy crude oil blends to the WCS stream. During 2013, the Company entered into a 20 year transportation agreement to ship 80,000 bbl/d of crude oil on the proposed Energy East pipeline originating at Hardisty, Alberta with delivery points in Quebec City, Quebec and Saint John, New Brunswick. This pipeline is subject to regulatory approval. The Company previously entered into a 20 year transportation agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans Mountain Expansion from Edmonton, Alberta to Vancouver, British Columbia. This pipeline is subject to regulatory approval. The Company has entered into a 20 year transportation agreement to ship 120,000 bbl/d of heavy crude oil on the proposed Keystone XL Pipeline from Hardisty, Alberta to the US Gulf Coast. In addition, the Company also entered into a 20 year crude oil purchase and sales agreement to sell 100,000 bbl/d of heavy crude oil to a major US refiner. The construction of the Keystone XL Pipeline is dependent on a Presidential Permit. Comparisons of the prices received in North America Exploration and Production by product type were as follows: (Yearly average) Wellhead Price (1) (2) Light and medium crude oil and NGLs (C$/bbl) Pelican Lake heavy crude oil (C$/bbl) Primary heavy crude oil (C$/bbl) Bitumen (thermal oil) (C$/bbl) Natural gas (C$/Mcf) (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. 2014 2013 2012 $ $ $ $ $ 76.94 $ 77.58 $ 76.29 $ 70.78 $ 4.72 $ 76.44 $ 70.62 $ 69.06 $ 66.14 $ 3.43 $ 72.20 68.84 66.64 66.46 2.57 NORTH SEA North Sea realized crude oil prices decreased 5% to average $106.63 per bbl for 2014 from $112.46 per bbl for 2013 (2012 – $111.90 per bbl). Realized crude oil prices per bbl in any particular period are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. OFFSHORE AFRICA Offshore Africa realized crude oil prices decreased 11% to average $97.81 per bbl for 2014 from $110.21 per bbl for 2013 (2012 – $111.18 per bbl). Realized crude oil prices per bbl in any particular year are dependent on the terms of the various sales contracts, the frequency and timing of liftings of each field, and prevailing crude oil prices and foreign exchange rates at the time of lifting. 32 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 32 15-03-12 6:20 PM ROYALTIES – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) North America Offshore Africa Company average Company average ($/BOE) (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2014 2013 2012 $ $ $ $ $ $ $ $ 13.74 $ 0.33 $ 6.83 $ 12.99 $ 0.36 $ 1.74 $ 0.38 $ 8.90 $ 11.30 $ 0.33 $ 18.18 $ 11.13 $ 0.14 $ 1.83 $ 0.18 $ 7.74 $ 10.33 0.29 29.46 10.67 0.06 1.77 0.09 7.07 NORTH AMERICA Government royalties on a significant portion of North America crude oil and NGLs production fall under the oil sands royalty regime and are calculated on a project by project basis as a percentage of gross revenue less operating, capital and abandonment costs incurred (“net profit”). Crude oil and NGLs royalties averaged approximately 19% of product sales for 2014 compared with 17% in 2013 (2012 – 16%) primarily due to higher realized crude oil prices. North America crude oil and NGLs royalties per bbl are anticipated to average 11.5% to 13.5% of product sales for 2015. Natural gas royalties averaged approximately 8% of product sales for 2014 compared with 5% in 2013 (2012 – 3%) primarily due to higher realized natural gas prices. North America natural gas royalties per Mcf are anticipated to average 3% to 4% of product sales for 2015. NORTH SEA The UK government royalties on crude oil were eliminated effective January 1, 2003. The remaining royalty is a gross overriding royalty on the Ninian field. OFFSHORE AFRICA Under the terms of the various Production Sharing Contracts, royalty rates fluctuate based on realized commodity pricing, capital and operating costs, the status of payouts, and the timing of liftings from each field. Royalty rates as a percentage of product sales averaged approximately 8% for 2014 compared with 17% for 2013 (2012 – 26%) primarily due to lower realized crude oil prices in 2014 and adjustments to royalties on liftings in 2013. Offshore Africa royalty rates are anticipated to average 3.5% to 5.5% of product sales for 2015. PRODUCTION EXPENSE – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore Africa Company average Natural gas ($/Mcf) (1) North America North Sea Offshore Africa Company average Company average ($/BOE) (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2014 2013 2012 $ $ $ $ $ $ $ $ $ 14.98 $ 74.04 $ 43.97 $ 18.25 $ 1.42 $ 9.10 $ 3.22 $ 1.48 $ 14.20 $ 66.19 $ 25.32 $ 17.14 $ 1.39 $ 4.67 $ 2.53 $ 1.42 $ 14.67 $ 14.24 $ 13.40 53.53 23.11 16.11 1.28 3.75 2.27 1.31 13.14 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 33 33 15-03-12 6:20 PM NORTH AMERICA North America crude oil and NGLs production expense for 2014 increased 5% to $14.98 per bbl from $14.20 per bbl for 2013 (2012 – $13.40 per bbl). The increase in production expense was primarily due to higher trucking and fuel costs across the heavy crude oil and thermal areas, together with higher servicing costs related to heavy crude oil production. North America crude oil and NGLs production expense is anticipated to average $12.50 to $14.50 per bbl for 2015. North America natural gas production expense for 2014 increased 2% to $1.42 per Mcf from $1.39 per Mcf for 2013 (2012 – $1.28 per Mcf). Natural gas production expense increased from 2013 due to the acquisitions of producing Canadian natural gas properties in 2014 that had higher production expense per Mcf than the Company’s existing properties. The production expense on the acquired assets has continued to decline as expected as they have become fully integrated into the Company’s operations. North America natural gas production expense is anticipated to average $1.30 to $1.40 per Mcf for 2015. NORTH SEA North Sea crude oil production expense for 2014 increased 12% to $74.04 per bbl from $66.19 per bbl for 2013 (2012 – $53.53 per bbl). Production expense increased due to natural field declines on relatively fixed cost structure, the impact of the unplanned downtime on theTiffany platform, and a weaker Canadian dollar. North Sea crude oil production expense is anticipated to average $48.00 to $52.00 per bbl for 2015 as the Banff FPSO has returned to the field and production has been reinstated. OFFSHORE AFRICA Offshore Africa crude oil production expense for 2014 increased 74% to $43.97 per bbl from $25.32 per bbl for 2013 (2012 – $23.11 per bbl). The increase in production expense from 2013 primarily reflects the impact of natural field declines on relatively fixed cost structure, the timing of liftings from various fields, which have different cost structures, a weaker Canadian dollar, and the impact of product inventory valuation adjustments in Olowi, Gabon in 2014. Offshore Africa crude oil production expense is anticipated to average $30.00 to $34.00 per bbl for 2015. DEPLETION, DEPRECIATION AND AMORTIZATION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) North America North Sea Offshore Africa Expense $/BOE (1) 2014 2013 3,901 $ 3,568 $ 269 105 4,275 $ 17.27 $ 552 134 4,254 $ 20.38 $ 2012 3,413 296 165 3,874 18.65 $ $ $ (1) Amounts expressed on a per unit basis are based on sales volumes. Depletion, depreciation and amortization expense for 2014 decreased 15% to $17.27 per BOE from $20.38 per BOE for 2013 (2012 – $18.65 per BOE) due to the impact of lower depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison field in 2013, as well as the impact of increased production on component depreciation determined on a straight-line. ASSET RETIREMENT OBLIGATION ACCRETION – EXPLORATION AND PRODUCTION ($ millions, except per BOE amounts) 2014 2013 North America North Sea Offshore Africa Expense $/BOE (1) $ $ $ 98 $ 38 10 146 $ 0.59 $ 92 $ 35 10 137 $ 0.66 $ 2012 85 27 7 119 0.57 (1) Amounts expressed on a per unit basis are based on sales volumes. Asset retirement obligation accretion expense decreased 11% to $0.59 per BOE from $0.66 per BOE for 2013 (2012 – $0.57 per BOE) primarily due to the impact of increased sales volumes. 34 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 34 15-03-12 6:20 PM OPERATING HIGHLIGHTS – OIL SANDS MINING AND UPGRADING OPERATIONS UPDATE The Company continues to focus on reliable and efficient operations. During 2014, operating performance continued to be strong, leading to average production of 110,571 bbl/d. PRODUCT PRICES, ROYALTIES AND TRANSPORTATION – OIL SANDS MINING AND UPGRADING ($/bbl) (1) SCO sales price Bitumen value for royalty purposes (2) Bitumen royalties (3) Transportation 2014 2013 $ $ $ $ 100.27 $ 67.63 $ 5.77 $ 1.85 $ 100.75 $ 65.48 $ 5.11 $ 1.57 $ 2012 90.74 59.93 4.34 1.83 (1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. (2) Calculated as the quarterly average of the bitumen valuation methodology price. (3) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. Realized SCO sales prices for 2014 was comparable with 2013 (2012 – $90.74 per bbl), reflecting lower benchmark pricing, offset by the impact of a weakening Canadian dollar. CASH PRODUCTION COSTS – OIL SANDS MINING AND UPGRADING The following tables are reconciled to the Oil Sands Mining and Upgrading production costs disclosed in note 20 to the Company’s consolidated financial statements. ($ millions) Cash production costs Less: costs incurred during turnaround periods Adjusted cash production costs Adjusted cash production costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs ($/bbl) (1) Adjusted cash production costs, excluding natural gas costs Adjusted natural gas costs Adjusted cash production costs 2014 2013 1,609 $ (98) 1,511 $ 1,395 $ 116 1,511 $ 1,567 $ (104) 1,463 $ 1,359 $ 104 1,463 $ 2014 2013 34.33 $ 2.85 37.18 $ 37.68 $ 2.89 40.57 $ 2012 1,504 (154) 1,350 1,254 96 1,350 2012 39.79 3.04 42.83 $ $ $ $ $ $ Sales (bbl/d) (2) 111,351 98,757 86,153 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Sales volumes include turnaround periods. Adjusted cash production costs averaged $37.18 per bbl for 2014, a decrease of 8% compared with $40.57 per bbl for 2013 (2012 – $42.83 per bbl). The decrease in 2014 adjusted cash production costs reflected increased plant capacity and reliability and the corresponding impact of higher production volumes on a relatively fixed cost structure, excluding the turnaround periods. Adjusted cash production costs are anticipated to average $32.00 to $35.00 per bbl for 2015. DEPLETION, DEPRECIATION AND AMORTIZATION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Depletion, depreciation and amortization Less: depreciation incurred during turnaround periods Adjusted depletion, depreciation and amortization $/bbl (1) 2014 2013 596 $ (28) 568 $ 582 $ (79) 503 $ 2012 447 (6) 441 13.97 $ 13.95 $ 13.99 $ $ $ (1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. Adjusted depletion, depreciation and amortization expense on a per bbl basis for 2014 was comparable with 2013 (2012 – $13.99 per bbl). Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 35 35 15-03-12 6:20 PM ASSET RETIREMENT OBLIGATION ACCRETION – OIL SANDS MINING AND UPGRADING ($ millions, except per bbl amounts) Expense $/bbl (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2014 47 $ 1.16 $ 2013 34 $ 0.94 $ 2012 32 1.01 $ $ Asset retirement obligation accretion expense represents the increase in the carrying amount of the asset retirement obligation due to the passage of time. MIDSTREAM ($ millions) Revenue Production expense Midstream cash flow Depreciation Equity loss from investment Segment earnings before taxes $ $ 2014 120 $ 34 86 9 8 2013 2012 110 $ 34 76 8 4 93 29 64 7 9 48 69 $ 64 $ The Company’s Midstream assets include three crude oil pipeline systems and a 50% working interest in an 84-megawatt cogeneration plant at Primrose. Approximately 85% of the Company’s heavy crude oil production is transported to international mainline liquid pipelines via the 100% owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned Cold Lake Pipeline. The Midstream pipeline assets allow the Company to control the transport of a portion of its own production volumes as well as earn third party revenue. This transportation control enhances the Company’s ability to manage the full range of costs associated with the development and marketing of its heavier crude oil. The Company has a 50% interest in the North West Redwater Partnership (“Redwater Partnership”). Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the “Project”) under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement. During 2014, Redwater Partnership, the Company and APMC amended certain terms of the processing agreements. In conjunction with these amendments, in order to provide financing for Project completion based on the current revised Project cost estimate of approximately $8,500 million, the Company, along with APMC, each committed to provide additional funding up to $350 million by January 2016 in the form of subordinated debt bearing interest at prime plus 6%. During 2014, the Company and APMC each provided $113 million of subordinated debt. Subsequent to December 31, 2014, the Company and APMC each provided an additional $112 million of subordinated debt. Should final Project costs exceed the revised cost estimate, the Company and APMC have agreed, subject to the Company being able to meet certain funding conditions, to fund any shortfall in available third party commercial lending required to attain Project completion. During 2014, Redwater Partnership executed a $3,500 million syndicated credit facility with a group of financial institutions maturing June 2018 and repaid and cancelled its $1,200 million credit facility previously in place. As at December 31, 2014, Redwater Partnership had borrowings of $913 million under the syndicated credit facility. In addition, during 2014, Redwater Partnership issued $500 million of 3.20% series A senior secured bonds due July 2024 and $500 million of 4.05% series B senior secured bonds due July 2044. Subsequent to December 31, 2014, Redwater Partnership issued $500 million of 2.10% series C senior secured bonds due February 2022 and $500 million of 3.70% series D senior secured bonds due February 2043. Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018, the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll, including interest, fees and principal repayments, of the syndicated credit facility and bonds, over the tolling period of 30 years. Redwater Partnership has entered into various agreements related to the engineering, procurement and construction of the Project. These contracts can be cancelled by Redwater Partnership upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. 36 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 36 15-03-12 6:20 PM ADMINISTRATION EXPENSE ($ millions, except per BOE amounts) Expense $/BOE (1) 2014 2013 $ $ 367 $ 1.28 $ 335 $ 1.37 $ 2012 270 1.13 (1) Amounts expressed on a per unit basis are based on sales volumes. Administration expense for 2014 decreased 7% to $1.28 per BOE from $1.37 per BOE for 2013 (2012 – $1.13 per BOE) primarily due to the impact of higher sales volumes. SHARE-BASED COMPENSATION ($ millions) Expense (Recovery) 2014 2013 $ 66 $ 135 $ 2012 (214) The Company’s stock option plan provides current employees with the right to receive common shares or a cash payment in exchange for stock options surrendered. The share-based compensation liability at December 31, 2014 reflected the Company’s liability for awards granted to employees at fair value estimated using the Black-Scholes valuation model. In periods when substantial share price changes occur, the Company’s net earnings are subject to significant volatility. The Company utilizes its share-based compensation plan to attract and retain employees in a competitive environment. All employees participate in this plan. The Company recorded a $66 million share-based compensation expense for 2014, primarily as a result of remeasurement of the fair value of outstanding stock options related to the impact of normal course graded vesting of stock options granted in prior periods, the impact of vested stock options exercised or surrendered during the year, and changes in the Company’s share price. During 2014, the Company capitalized $14 million of share-based compensation costs to property, plant and equipment in the Oil Sands Mining and Upgrading segment (2013 – $25 million costs; 2012 – $12 million recovery). During 2014, the Company paid $8 million for stock options surrendered for cash settlement (2013 – $4 million; 2012 – $7 million). INTEREST AND OTHER FINANCING EXPENSE ($ millions, except per BOE amounts and interest rates) Expense, gross Less: capitalized interest Expense, net $/BOE (1) Average effective interest rate (1) Amounts expressed on a per unit basis are based on sales volumes. $ $ $ 2014 527 $ 204 323 $ 1.12 $ 3.9% 2013 454 $ 175 279 $ 1.14 $ 4.4% 2012 462 98 364 1.52 4.8% Gross interest and other financing expense for 2014 increased from 2013 primarily due to the impact of higher overall debt levels. Capitalized interest of $204 million for 2014 was primarily related to the Horizon Phase 2/3 expansion. The Company’s average effective interest rate for 2014 decreased from 2013 due to the repayment of higher interest rate US dollar debt securities, the issuance of lower interest rate US dollar debt securities, and an increase in the utilization of the lower cost US commercial paper program that was implemented in 2013. Net interest and other financing expense for 2014 decreased 2% to $1.12 per BOE from $1.14 per BOE for 2013 (2012 – $1.52 per BOE) primarily due to the impact of increased sales volumes. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 37 37 15-03-12 6:20 PM RISK MANAGEMENT ACTIVITIES The Company utilizes various derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These derivative financial instruments are not intended for trading or speculative purposes. ($ millions) Crude oil and NGLs financial instruments Natural gas financial instruments Foreign currency contracts Realized (gain) loss Crude oil and NGLs financial instruments Natural gas financial instruments Foreign currency contracts Unrealized (gain) loss Net (gain) loss 2014 (284) $ 34 (99) (349) $ (427) $ (3) (21) (451) $ (800) $ 2013 2012 44 $ – (160) (116) $ 17 $ 3 19 39 $ (77) $ 65 – 97 162 3 – (45) (42) 120 $ $ $ $ $ During 2014, net realized risk management gains and losses were related to the settlement of crude oil, natural gas and foreign currency contracts. The Company recorded a net unrealized gain of $451 million ($339 million after-tax) on its risk management activities (2013 – $39 million unrealized loss, $32 million after-tax; 2012 – $42 million unrealized gain, $37 million after-tax), primarily related to changes in the fair value of these contracts. The cash settlement amount of commodity and foreign currency derivative financial instruments may vary materially depending upon the underlying crude oil and natural gas prices and foreign exchange rates at the time of final settlement, as compared to their fair value at December 31, 2014. Complete details related to outstanding derivative financial instruments at December 31, 2014 are disclosed in note 17 to the Company’s consolidated financial statements. FOREIGN EXCHANGE ($ millions) Net realized loss (gain) Net unrealized loss (1) Net loss (gain) 2014 2013 47 $ 256 303 $ (16) $ 226 210 $ 2012 (178) 129 (49) $ $ (1) Amounts are reported net of the hedging effect of cross currency swaps. The Company’s operating results are affected by the fluctuations in the exchange rates between the Canadian dollar, US dollar, and UK pound sterling. Predominantly all of the Company’s revenue is based on reference to US dollar benchmark prices. An increase in the value of the Canadian dollar in relation to the US dollar results in decreased revenue from the sale of the Company’s production. Conversely a decrease in the value of the Canadian dollar in relation to the US dollar results in increased revenue from the sale of the Company’s production. Production expenses in the North Sea are subject to foreign currency fluctuations due to changes in the exchange rate of the UK pound sterling to the US and Canadian dollars. Production expenses in Offshore Africa are subject to foreign currency fluctuations due to changes in the exchange rate of the US dollar to the Canadian dollar. The value of the Company’s US dollar denominated debt is also impacted by the value of the Canadian dollar in relation to the US dollar. The net realized foreign exchange loss for 2014 was primarily due to foreign exchange rate fluctuations on settlement of working capital items denominated in US dollars or UK pounds sterling and the repayment of US$500 million of 1.45% notes and US$350 million of 4.90% notes. The net unrealized foreign exchange loss in 2014 was primarily related to the impact of a weaker Canadian dollar with respect to remaining US dollar debt, partially offset by the reversal of the net unrealized foreign exchange loss on the repayment of US$500 million of 1.45% notes and US$350 million of 4.90% notes. Included in the net unrealized loss for 2014 was an unrealized gain of $259 million (2013 – $165 million unrealized gain, 2012 – $53 million unrealized loss) related to the impact of cross currency swaps.The US/Canadian dollar exchange rate at December 31, 2014 was US$0.8620 (December 31, 2013 – US$0.9402; December 31, 2012 – US$1.0051). 38 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 38 15-03-12 6:20 PM INCOME TAXES ($ millions, except income tax rates) North America (1) North Sea Offshore Africa (2) PRT (recovery) expense – North Sea Other taxes Current income tax expense Deferred income tax expense Deferred PRT expense (recovery) – North Sea Deferred income tax expense (recovery) Income tax rate and other legislative changes 2014 2013 2012 $ 702 $ 544 $ (68) 43 (273) 23 427 681 126 807 1,234 – 23 202 (56) 22 735 163 (132) 31 766 (15) $ 1,234 $ 751 $ 366 115 206 44 16 747 – (30) (30) 717 (58) 659 Effective income tax rate on adjusted net earnings from operations (3) 24.6% 26.2% 27.8% Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. Includes current income taxes relating to disposition of properties in 2013. (1) (2) (3) Excludes the impact of current and deferred PRT expense and other current income tax expense. Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. The current PRT recovery in the North Sea in 2014 included the impact of amendments to tax filings for prior years. During 2013, the Government of British Columbia substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $15 million. During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax relief on UK North Sea decommissioning expenditures to 50%. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $58 million. The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s results of operations, financial position or liquidity. During 2014, the Company filed Scientific Research and Experimental Development claims of approximately $450 million (2013 – $390 million; 2012 – $300 million) relating to qualifying research and development expenditures for Canadian income tax purposes. For 2015, based on forward commodity prices and the current availability of tax pools, the Company expects to incur current income tax expense of $300 million to $400 million in Canada and recoveries of $190 million to $220 million in the North Sea and Offshore Africa. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 39 39 15-03-12 6:20 PM NET CAPITAL EXPENDITURES (1) ($ millions) Exploration and Evaluation Net expenditures (proceeds) (2) (3) Property, Plant and Equipment Net property acquisitions (2) Well drilling, completion and equipping Production and related facilities Capitalized interest and other (4) Net expenditures Total Exploration and Production Oil Sands Mining and Upgrading Horizon Phases 2/3 construction costs Sustaining capital Turnaround costs Capitalized interest and other (4) Total Oil Sands Mining and Upgrading Midstream Abandonments (5) Head office Total net capital expenditures By segment North America (2) North Sea Offshore Africa (3) Oil Sands Mining and Upgrading Midstream Abandonments (5) Head office Total 2014 2013 2012 $ 1,190 $ (144) $ 309 2,893 2,162 1,830 106 6,991 8,181 2,502 352 29 227 3,110 62 346 45 11,744 $ 7,500 $ 400 281 3,110 62 346 45 11,744 $ $ $ $ 246 2,140 1,878 120 4,384 4,240 2,057 278 100 157 2,592 197 207 38 7,274 $ 4,026 $ 334 (120) 2,592 197 207 38 7,274 $ 144 1,902 1,978 111 4,135 4,444 1,315 223 21 51 1,610 14 204 36 6,308 4,126 254 64 1,610 14 204 36 6,308 Includes Business Combinations. Includes proceeds from the Company’s disposition of a 50% interest in its exploration right in South Africa in 2013. (1) Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values, and other fair value adjustments. (2) (3) (4) Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments. (5) Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. The Company’s strategy is focused on building a diversified asset base that is balanced among various products. In order to facilitate efficient operations, the Company concentrates its activities in core areas. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By owning associated infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Net capital expenditures for 2014 were $11,744 million compared with $7,274 million for 2013 (2012 – $6,308 million). The increase in 2014 capital expenditures from 2013 was primarily due to the acquisition of Canadian crude oil and natural gas properties in 2014. On April 1, 2014, the Company completed the acquisition of certain Canadian crude oil and natural gas properties, including exploration and evaluation assets of $823 million, for cash consideration of $3,110 million, subject to final closing adjustments. During 2014, the Company also acquired a number of additional producing crude oil and natural gas properties in the North American Exploration and Production segment for net cash consideration of $643 million, resulting in a non-cash gain of $137 million. During 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in an after-tax gain on sale of exploration and evaluation property of $166 million. In the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. 40 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 40 15-03-12 6:20 PM Included in the Company’s original 2015 budget was approximately $2,000 million of capital flexibility, which allows the Company to reallocate capital over 2015 as required. In response to declining commodity prices, in December 2014 the Company proactively reviewed its capital allocation strategy and in January 2015 announced that it would access this capital flexibility to reduce capital spending by approximately $2,400 million. Subsequently, capital expenditure guidance for 2015 has been further reduced by $150 million as a result of the reduction in scope of the originally planned 2015 Horizon maintenance turnaround from 35 days to 6 days. The Company has significant additional capital flexibility in 2015 to further curtail capital spending if required or increase capital spending if commodity prices strengthen. For additional details, refer to the “Outlook” section of this MD&A. Drilling Activity (number of wells) Net successful natural gas wells Net successful crude oil wells (1) Dry wells Stratigraphic test / service wells Total Success rate (excluding stratigraphic test / service wells) (1) Includes bitumen wells. 2014 75 1,023 19 437 1,554 98% 2013 44 1,117 30 384 1,575 97% 2012 35 1,203 33 727 1,998 97% NORTH AMERICA North America, excluding Oil Sands Mining and Upgrading, accounted for approximately 66% of the total capital expenditures for 2014 compared to approximately 59% for 2013 (2012 – 69%). During 2014, the Company targeted 76 net natural gas wells, including 28 wells in Northeast British Columbia, 38 wells in Northwest Alberta and 10 wells in Northern Plains. The Company also targeted 1,036 net crude oil wells. The majority of these wells were concentrated in the Company’s Northern Plains region where 896 primary heavy crude oil wells, 24 Pelican Lake heavy crude oil wells, 15 bitumen (thermal oil) wells and 5 light crude oil wells were drilled. Another 96 wells targeting light crude oil were drilled outside the Northern Plains region. The Company continued to access its large crude oil drilling inventory to maximize value in both the short and long term. Due to the Company’s focus on drilling crude oil wells in recent years, natural gas drilling activities have been reduced from historical levels. Deferred natural gas well locations have been retained in the Company’s prospect inventory. During 2013, the Company discovered bitumen emulsion at surface in areas of the Primrose field. The Company continues to work with the regulator on the causation review of the bitumen emulsion seepage. The Company’s near-term steaming plan at Primrose has been modified, with steaming being reduced in certain areas. Overall thermal oil production for 2014 averaged approximately 107,800 bbl/d, compared with approximately 96,500 bbl/d in 2013 (2012 – 99,500 bbl/d). Production volumes reflected the cyclic nature of thermal oil production at Primrose and production at Kirby South. In response to declining commodity prices, in January 2015 the Company deferred development activities in the Kirby North Project. Development of the tertiary recovery conversion projects at Pelican Lake continued and 24 horizontal wells were drilled during 2014. Pelican Lake production averaged approximately 50,100 bbl/d in 2014 (2013 – 42,900; 2012 – 38,200 bbl/d). In order to expand its pipeline infrastructure the Company has participated in the expansion of the Cold Lake pipeline system. Initial pipeline commissioning activities are expected to commence in the first quarter of 2015 with the final phases of the project expected to continue for approximately three years. OIL SANDS MINING AND UPGRADING Phase 2/3 expansion activity in 2014 was focused on field construction of the gas recovery unit, sulphur recovery unit, butane treatment unit, coker expansion, hydrogen unit, hydrotreater unit, vacuum distillation unit and distillation recovery unit, tank farms, cooling water tower, tailings, hydrotransport, froth treatment, tailings transfer pumphouses and pipelines, extraction plants, and ore preparation plant civil works along with engineering and procurement related to the ore preparation plants, froth treatment plant, hydrotransport, sourwater concentrator and combined hydrotreater. Budgeted capital spending in 2015 has been revised from $2,450 million to $2,200 million through targeted cost efficiencies, while maintaining planned expansion activities. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 41 41 15-03-12 6:20 PM NORTH SEA During 2014, the Company completed a five gross well drilling program at the Ninian field, supported by the Brownfield Allowance program. Subsequent to December 31, 2014, the Company reduced its 2015 drilling program to one well and suspended all other development activities. The decommissioning activities at the Murchison platform are ongoing and are expected to continue for approximately five years. OFFSHORE AFRICA During 2014, in Côte d’Ivoire, the Company contracted a drilling rig for a 10 gross well development program at the Espoir field. Subsequent to December 31, 2014, the Company drilled the first well with first oil anticipated at the end of the first quarter of 2015. At the Baobab field, during 2014, the Company secured a drilling rig and subsequent to December 31, 2014, the rig arrived on location. The Company has commenced drilling the first well of its six gross well program with first oil anticipated in the second quarter of 2015. In Côte d’Ivoire, during 2014, the operator in Block CI-514 completed drilling an exploratory well and encountered the presence of light oil. The well was plugged and the data gathered will now be evaluated to determine the extent of the accumulation and the forward plan for appraisal. The operator anticipates drilling a second exploratory well in the second quarter of 2015. In South Africa, during 2014, the exploration well drilled on Block 11B/12B was suspended due to mechanical issues with marine equipment on the drilling rig. The rig safely left the well location and, as the available drilling window had ended, it was demobilized by the operator. The South African authorities have formally confirmed that the well drilled satisfies the work obligation for the initial period of the Block 11B/12B Exploration Right. The operator is reviewing the course of action to re-enter the well, and has indicated drilling operations are unlikely to resume in the area before 2016. LIQUIDITY AND CAPITAL RESOURCES ($ millions, except ratios) Working capital deficit (1) Long-term debt (2) (3) Shareholders’ equity Share capital Retained earnings Accumulated other comprehensive income Total Debt to book capitalization (3) (4) Debt to market capitalization (3) (5) After-tax return on average common shareholders’ equity (6) After-tax return on average capital employed (3) (7) $ $ $ $ 2014 2013 673 $ 14,002 $ 1,574 $ 9,661 $ 4,432 $ 24,408 51 28,891 $ 3,854 $ 21,876 42 25,772 $ 33% 26% 14% 10% 27% 20% 9% 7% 2012 1,264 8,736 3,709 20,516 58 24,283 26% 22% 8% 7% Includes the current portion of long-term debt (2014 – $980 million; 2013 – $1,444 million; 2012 – $798 million). (1) Calculated as current assets less current liabilities, excluding the current portion of long-term debt. (2) (3) Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and transaction costs. (4) Calculated as current and long-term debt; divided by the book value of common shareholders’ equity plus current and long-term debt. (5) Calculated as current and long-term debt; divided by the market value of common shareholders’ equity plus current and long-term debt. (6) Calculated as net earnings for the twelve month trailing period; as a percentage of average common shareholders’ equity for the year. (7) Calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed for the year. At December 31, 2014, the Company’s capital resources consisted primarily of cash flow from operations, available bank credit facilities and access to debt capital markets. Cash flow from operations and the Company’s ability to renew existing bank credit facilities and raise new debt is dependent on factors discussed in the “Risks and Uncertainties” section of this MD&A. In addition, the Company’s ability to renew existing bank credit facilities and raise new debt is also dependent upon maintaining an investment grade debt rating and the condition of capital and credit markets. The Company continues to believe that its internally generated cash flow from operations supported by the implementation of its ongoing hedge policy, the flexibility of its capital expenditure programs supported by its multi-year financial plans, its existing bank credit facilities, and its ability to raise new debt on commercially acceptable terms will provide sufficient liquidity to sustain its operations in the short, medium and long term and support its growth strategy. 42 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 42 15-03-12 6:20 PM On an ongoing basis the Company continues to focus on its balance sheet strength and available liquidity by: ■■ Monitoring cash flow from operations, which is the primary source of funds; ■■ Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. In response to declining commodity prices in late 2014, the Company exercised its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt; ■■ Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. During the first quarter of 2015, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. In addition, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018; and, ■■ Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. During 2013, the Company established a US commercial paper program. Borrowings of up to a maximum US$1,500 million are authorized. The Company reserves capacity under its bank credit facilities for amounts outstanding under this program. At December 31, 2014, the Company had in place bank credit facilities of $5,627 million, of which approximately $2,643 million, net of commercial paper issuances of $580 million, was available for general corporate purposes. Subsequent to December 31, 2014, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018 and extended the existing $1,000 million non-revolving term credit facility originally maturing March 2016 to January 2017. During 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. The Company issued US$500 million of three-month LIBOR plus 0.375% notes due March 2016, and concurrently entered into cross currency swaps to fix the foreign currency exchange rate risk at three-month CDOR plus 0.309% and $555 million. In addition, the Company issued US$500 million of 3.80% notes due April 2024, US$600 million of 1.75% notes due January 2018, and US$600 million of 3.90% notes due February 2025. Proceeds from the securities were used to repay bank indebtedness. During 2014, the Company issued $500 million of 2.60% medium-term notes due December 2019 and $500 million of 3.55% medium-term notes due June 2024. Proceeds from the securities were used for general corporate purposes and repayment of bank indebtedness. At December 31, 2014, the Company had $400 million of long-term debt maturing over the next 12 months ($400 million due June 2015). Long-term debt was $14,002 million at December 31, 2014, resulting in a debt to book capitalization ratio of 33% (December 31, 2013 – 27%; December 31, 2012 – 26%). This ratio is within the 25% to 45% internal range utilized by management. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flow from operations is greater than current investment activities. The Company remains committed to maintaining a strong balance sheet, adequate available liquidity and a flexible capital structure. The Company has hedged a portion of its production for 2015 at prices that protect investment returns to support ongoing balance sheet strength and the completion of its capital expenditure programs. Further details related to the Company’s long-term debt at December 31, 2014 are discussed in note 9 to the Company’s consolidated financial statements. The Company’s commodity hedge policy reduces the risk of volatility in commodity prices and supports the Company’s cash flow for its capital expenditure programs. This policy currently allows for the hedging of up to 60% of the near 12 months budgeted production and up to 40% of the following 13 to 24 months estimated production. For the purpose of this policy, the purchase of put options is in addition to the above parameters. As at March 4, 2015, 50,000 bbl/d of currently forecasted 2015 crude oil volumes were hedged using price collars.The Company has also entered into 30,000 bbl/d of crude oil WCS differential swaps in the first quarter of 2015. Further details related to the Company’s commodity derivative financial instruments outstanding at December 31, 2014 are discussed in note 17 to the Company’s consolidated financial statements. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 43 43 15-03-12 6:20 PM SHARE CAPITAL As at December 31, 2014, there were 1,091,837,000 common shares outstanding (December 31, 2013 – 1,087,322,000 common shares) and 71,708,000 stock options outstanding. As at March 3, 2015, the Company had 1,092,528,000 common shares outstanding and 70,576,000 stock options outstanding. On March 4, 2015, the Board of Directors approved an increase in the annual dividend to $0.92 per common share (previous annual dividend rate of $0.90 per common share), beginning with the quarterly dividend payable on April 1, 2015 at $0.23 per common share. This reflects confidence in the Company’s cash flow and provides a return to shareholders. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. During 2014, the Company announced a Normal Course Issuer Bid to purchase through the facilities of the TSX and the NYSE, during the twelve month period commencing April 2014 and ending April 2015, up to 54,596,899 common shares. The Company’s Normal Course Issuer Bid announced in 2013 expired April 2014. During 2014, the Company purchased for cancellation 10,095,000 common shares at a weighted average price of $44.85 per common share for a total cost of $453 million. Retained earnings were reduced by $414 million, representing the excess of the purchase price of common shares over their average carrying value. COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS In the normal course of business, the Company has entered into various commitments that will have an impact on the Company’s future operations. The following table summarizes the Company’s commitments as at December 31, 2014: ($ millions) 2015 2016 2017 2018 2019 Thereafter Product transportation and pipeline Offshore equipment operating leases and offshore drilling Long-term debt (1) Interest and other financing expense (2) Office leases Other $ $ $ $ $ $ 442 $ 334 $ 301 $ 268 $ 237 $ 1,512 341 $ 980 $ 555 $ 42 $ 204 $ 92 $ 2,397 $ 525 $ 42 $ 125 $ 66 $ 2,153 $ 445 $ 44 $ 40 $ 59 $ 1,160 $ 378 $ 46 $ 1 $ 19 $ 1,000 $ 350 $ 47 $ – $ – 6,395 4,202 284 – (1) Long-term debt represents principal repayments only and does not reflect original issue discounts or transaction costs. (2) Interest and other financing expense amounts represent the scheduled fixed rate and variable rate cash interest payments related to long-term debt. Interest on variable rate long-term debt was estimated based upon prevailing interest rates and foreign exchange rates as at December 31, 2014. In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of subsequent phases of Horizon.These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. LEGAL PROCEEDINGS AND OTHER CONTINGENCIES The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims.The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position. RESERVES For the years ended December 31, 2014, 2013 and 2012, the Company retained Independent Qualified Reserves Evaluators to evaluate and review all of the Company’s proved and proved plus probable crude oil, NGLs and natural gas 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. 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 FASB Topic 932 “Extractive Activities - Oil and Gas” in the Company’s annual report on Form 40-F filed with the SEC and in the “Supplementary Oil and Gas Information” section of the Company’s Annual Report. 44 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 44 15-03-12 6:20 PM The following tables summarize the company gross proved and proved plus probable reserves using forecast prices and costs as at December 31, 2014, prepared in accordance with NI 51-101 reserves disclosures: Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) 440 1 7 4 – 31 (1) (17) 9 (29) 445 244 – 29 12 – – – (1) (3) (52) 229 258 1,157 2,211 4,305 110 5,137 – – – – – – – 34 (18) 274 – 91 – – – – – 8 (39) 1,217 – – – – – – (4) (9) (40) 2,158 14 121 562 – 1,407 (1) (58) 219 (568) 6,001 1 5 32 – 34 – (1) 20 (13) 188 5 152 142 – 300 (1) (33) 97 (288) 5,511 Light and Medium Crude Oil (MMbbl) Primary Heavy Crude Oil (MMbbl) Pelican Lake Heavy Crude Oil (MMbbl) Bitumen (Thermal Oil) (MMbbl) Synthetic Crude Oil (MMbbl) Natural Gas (Bcf) Natural Gas Liquids (MMbbl) Barrels of Oil Equivalent (MMBOE) Proved Reserves December 31, 2013 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 Proved Plus Probable Reserves December 31, 2013 644 334 362 2,170 3,289 6,109 174 7,991 Discoveries Extensions Infill Drilling Improved Recovery Acquisitions Dispositions Economic Factors Technical Revisions Production December 31, 2014 2 12 7 – 40 (1) (3) (12) (29) 660 – 41 16 – – – (1) (21) (52) 317 – – 1 – – – – – 134 – – – – – 50 (18) 395 47 (39) 2,312 – 358 – – – – (11) (3) (40) 3,593 17 178 741 – 1,892 (1) (49) (181) (568) 8,138 1 8 43 – 47 – (1) (1) (13) 258 6 583 191 – 403 (1) (24) 30 (288) 8,891 At December 31, 2014, the company gross proved crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 4,511 MMbbl, and gross proved plus probable crude oil, bitumen (thermal oil), SCO and NGLs reserves totaled 7,535 MMbbl. Proved reserve additions and revisions replaced 148% of 2014 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 246 MMbbl, and additions to proved plus probable reserves amounted to 709 MMbbl. Net positive revisions amounted to 36 MMbbl for proved reserves and 44 MMbbl for proved plus probable reserves, primarily due to technical revisions to prior estimates. At December 31, 2014, the company gross proved natural gas reserves totaled 6,001 Bcf, and gross proved plus probable natural gas reserves totaled 8,138 Bcf. Proved reserve additions and revisions replaced 399% of 2014 production. Additions to proved reserves resulting from exploration and development activities, acquisitions and future offset additions amounted to 2,103 Bcf, and additions to proved plus probable reserves amounted to 2,827 Bcf. Net positive revisions amounted to 161 Bcf for proved reserves and net negative revisions amounted to 230 Bcf for proved plus probable reserves, primarily due to technical revisions to prior estimates. The Reserves Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of the Company’s Independent Qualified Reserves Evaluators to review the qualifications of and procedures used by each evaluator in determining the estimate of the Company’s quantities and related net present value of future net revenue of the remaining reserves. Additional reserves disclosure is annually disclosed in the AIF and the “Supplementary Oil and Gas Information” section of the Company’s Annual Report. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:46 25079_CNR_2014_AR_BOOK.indb 45 45 15-03-12 6:20 PM RISKS AND UNCERTAINTIES The Company is exposed to various operational risks inherent in the exploration, development, production and marketing of crude oil and NGLs and natural gas and the mining and upgrading of bitumen into SCO. These inherent risks include, but are not limited to, the following: ■■ The ability to find, produce and replace reserves, whether sourced from exploration, improved recovery or acquisitions, at a reasonable cost, including the risk of reserve revisions due to economic and technical factors. Reserve revisions can have a positive or negative impact on asset valuations, ARO and depletion rates; ■■ Reservoir quality and uncertainty of reserve estimates; ■■ Volatility in the prevailing prices of crude oil and NGLs and natural gas; ■■ Regulatory risk related to approval for exploration and development activities, which can add to costs or cause delays in projects; ■■ Labour risk associated with securing the manpower necessary to complete capital projects in a timely and cost effective manner; ■■ 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; ■■ Timing and success of integrating the business and operations of acquired properties and/or companies; ■■ Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts, including derivative financial instruments and physical sales contracts as part of a hedging program; ■■ Interest rate risk associated with the Company’s ability to secure financing on commercially acceptable terms; ■■ Foreign exchange risk due to fluctuating exchange rates on the Company’s US dollar denominated debt and as all sales are predominantly based on US dollar denominated benchmarks; ■■ Environmental impact risk associated with exploration and development activities, including GHG; ■■ Geopolitical risks associated with changing governments or governmental policies, social instability and other political, economic or diplomatic developments in the regions where the Company has its operations; ■■ Future legislative and regulatory developments related to environmental regulation; ■■ Potential actions of governments, regulatory authorities and other stakeholders that may result in costs or restrictions in the jurisdictions where the Company has operations; ■■ Changing royalty regimes; ■■ Business interruptions because of unexpected events such as fires or explosions whether caused by human error or nature, severe storms and other calamitous acts of nature, blowouts, freeze-ups, mechanical or equipment failures of facilities and infrastructure and other similar events affecting the Company or other parties whose operations or assets directly or indirectly impact the Company and that may or may not be financially recoverable; ■■ The access to markets for the Company’s products; and ■■ Other circumstances affecting revenue and expenses. The Company uses a variety of means to help mitigate and/or minimize these risks. The Company maintains a comprehensive property loss and business interruption insurance program to reduce risk. Operational control is enhanced by focusing efforts on large core areas with high working interests and by assuming operatorship of key facilities. Product mix is diversified, consisting of the production of natural gas and the production of crude oil of various grades. The Company believes this diversification reduces price risk when compared with over-leverage to one commodity. Accounts receivable from the sale of crude oil and natural gas are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. Derivative financial instruments are utilized to help ensure targets are met and to manage commodity price, foreign currency and interest rate exposures. The Company is exposed to possible losses in the event of non-performance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with substantially all investment grade financial institutions and other entities. The arrangements and policies concerning the Company’s financial instruments are under constant review and may change depending upon the prevailing market conditions. The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. For additional details regarding the Company’s risks and uncertainties, refer to the Company’s AIF for the year ended December 31, 2014. 46 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 46 15-03-12 6:20 PM ENVIRONMENT The Company continues to invest in people, technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efficiently and in an environmentally sustainable manner. The crude oil and natural gas industry is experiencing incremental increases in costs related to environmental regulation, particularly in North America and the North Sea. Existing and expected legislation and regulations require the Company to address and mitigate the effect of its activities on the environment. Increasingly stringent laws and regulations may have an adverse effect on the Company’s future net earnings and cash flow from operations. The Company’s associated environmental risk management strategies focus on working with legislators and regulators to ensure that any new or revised policies, legislation or regulations properly reflect a balanced approach to sustainable development. Specific measures in response to existing or new legislation include a focus on the Company’s energy efficiency, air emissions management, released water quality, reduced fresh water use and the minimization of the impact on the landscape.Training and due diligence for operators and contractors are key to the effectiveness of the Company’s environmental management programs and the prevention of incidents. The Company’s environmental risk management strategies employ an Environmental Management Plan (the “Plan”). Details of the Plan, along with performance results, are presented to, and reviewed by, the Board of Directors quarterly. The Company’s Plan and operating guidelines focus on minimizing the impact of operations while meeting regulatory requirements, regional management frameworks, industry operating standards and guidelines, and internal corporate standards. The Company, as part of this Plan, has implemented a proactive program that includes: ■■ An internal environmental compliance audit and inspection program of the Company’s operating facilities; ■■ A suspended well inspection program to support future development or eventual abandonment; ■■ Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; ■■ An effective surface reclamation program; ■■ A due diligence program related to groundwater monitoring; ■■ An active program related to preventing and reclaiming spill sites; ■■ A solution gas conservation program; ■■ A program to replace the majority of fresh water for steaming with brackish water; ■■ Water programs to improve efficiency of use, recycle rates and water storage; ■■ Environmental planning for all projects to assess impacts and to implement avoidance and mitigation programs; ■■ Reporting for environmental liabilities; ■■ A program to optimize efficiencies at the Company’s operated facilities; ■■ Continued evaluation of new technologies to reduce environmental impacts and support for Canada’s Oil Sands Innovation Alliance (“COSIA”); ■■ CO2 reduction programs including the injection of CO2 into tailings and for use in EOR; ■■ A program in place related to progressive reclamation and tailings management at Horizon; and ■■ Participation and support for the Joint Oil Sands Monitoring Program. The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 4.6% (2013 – 5.0%; 2012 – 4.3%). For 2014, the Company’s capital expenditures included $346 million for abandonment expenditures (2013 – $207 million; 2012 – $204 million). The Company’s estimated discounted ARO at December 31, 2014 was as follows: ($ millions) Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream 2014 2013 $ $ 2,012 $ 1,169 255 783 2 4,221 $ 1,707 1,090 225 1,138 2 4,162 The discounted ARO was based on estimates of future costs to abandon and restore wells, production facilities, mine site, upgrading facilities and tailings, and offshore production platforms. Factors that affect costs include number of wells drilled, well depth, facility size and the specific environmental legislation. The estimated future costs are based on engineering estimates of current costs in accordance with present legislation, industry operating practice and the expected timing of abandonment. The Company’s strategy in the North Sea consists of developing commercial hubs around its core operated properties with the goal of increasing production and extending the economic lives of its production facilities, thereby delaying the eventual abandonment dates. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 47 47 15-03-12 6:20 PM GREENHOUSE GAS AND OTHER AIR EMISSIONS The Company, through the Canadian Association of Petroleum Producers, is working with Canadian legislators and regulators as they develop and implement new GHG emission laws and regulations. Internally, the Company is pursuing an integrated emissions reduction strategy, to ensure that it is able to comply with existing and future emissions reduction requirements, for both GHGs and air pollutants (such as sulphur dioxide and oxides of nitrogen). The Company continues to develop strategies that will enable it to deal with the risks and opportunities associated with new GHG and air emissions policies. In addition, the Company is working with relevant parties to ensure that new policies encourage technological innovation, energy efficiency, and targeted research and development while not impacting competitiveness. In Canada, the federal government has indicated its intent to develop regulations to address industrial GHG emissions, as part of the national GHG reduction target. The federal government is also developing a comprehensive management system for air pollutants, and has released draft regulations pertaining to certain boilers, heaters and compressor engines operated by the Company. In the Province of Alberta, GHG reduction regulations came into effect July 1, 2007, affecting facilities emitting more than 100 kilotonnes of CO2e annually. Four of the Company’s facilities, the Horizon facility, the Primrose/Wolf Lake in situ heavy crude oil facilities, the Hays sour natural gas plant, and the Wapiti gas plant are subject to compliance under the regulations. The Kirby South in situ heavy crude oil facility will be subject to compliance under the regulations in 2016. In the Province of British Columbia, carbon tax is currently being assessed at $30/tonne of CO2e on fuel consumed and gas flared in the province. The province of Saskatchewan released draft GHG regulations that regulate facilities emitting more than 50 kilotonnes of CO2e annually and will likely require the North Tangleflags in situ heavy oil facility to meet the reduction target for its GHG emissions once the governing legislation comes into force. In the UK, GHG regulations have been in effect since 2005. In Phase 1 (2005 – 2007) of the UK National Allocation Plan, the Company operated below its CO2 allocation. In Phase 2 (2008 – 2012) the Company’s CO2 allocation was decreased below the Company’s operations emissions. In Phase 3 (2013 – 2020) the Company’s CO2 allocation was further reduced. The Company continues to focus on implementing reduction programs based on efficiency audits to reduce CO2 emissions at its major facilities and on trading mechanisms to ensure compliance with requirements now in effect. The United States Environmental Protection Agency (“EPA”) is proceeding to regulate GHGs under the Clean Air Act. This EPA action has been subject to legal and political challenges, the outcome of which cannot be predicted. The ultimate form of Canadian regulation is anticipated to be strongly influenced by the regulatory decisions made within the United States. Various states have enacted or are evaluating low carbon fuel standards, which may affect access to market for crude oil with higher emissions intensity. There are a number of unresolved issues in relation to Canadian federal and provincial GHG regulatory requirements. Key among them is the form of regulation, an appropriate common facility emission level, availability and duration of compliance mechanisms, and resolution of federal/provincial harmonization agreements. The Company continues to pursue GHG emission reduction initiatives including: solution gas conservation, compressor optimization to improve fuel gas efficiency, CO2 capture and sequestration in oil sands tailings, CO2 capture and storage in association with EOR, and participation in COSIA. The additional requirements of enacted or proposed GHG regulations on the Company’s operations may increase capital expenditures and operating expenses, including those related to Horizon and the Company’s other existing and certain planned oil sands projects. This may have an adverse effect on the Company’s future net earnings and cash flow from operations. Air pollutant standards and guidelines are being developed federally and provincially and the Company is participating in these discussions. Ambient air quality and sector based reductions in air emissions are being reviewed. Through Company and industry participation with stakeholders, guidelines are being developed that adopt a structured process to emission reductions that is commensurate with technological development and operational requirements. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of financial statements requires the Company to make estimates, assumptions and judgements in the application of IFRS that have a significant impact on the financial results of the Company. Actual results could differ from estimated amounts, and those differences may be material. DEPLETION, DEPRECIATION AND AMORTIZATION AND IMPAIRMENT Critical accounting policies and estimates are reviewed by the Company’s Audit Committee annually. The Company believes the following are the most critical accounting policies and estimates in preparing its consolidated financial statements. A) Exploration and evaluation (“E&E”) costs relating to activities to explore and evaluate crude oil and natural gas properties are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E assets are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. Technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. The judgements associated with the estimation of proved reserves are described below in “Crude Oil and Natural Gas Reserves”. 48 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 48 15-03-12 6:20 PM An alternative acceptable accounting method for E&E costs under IFRS 6 “Exploration for and Evaluation of Mineral Resources” is to charge exploratory dry holes and geological and geophysical exploration costs incurred after having obtained the legal rights to explore an area against net earnings in the period incurred rather than capitalizing to E&E assets. E&E assets are tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of Cash Generating Units (“CGUs”), aggregated at the segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. The determination of the fair value of CGUs requires the use of assumptions and estimates including future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and production costs, discount rates and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGU’s. Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Crude oil and natural gas properties in the Exploration and Production segments are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future estimated development expenditures required to develop proved reserves. Estimates of proved reserves have a significant impact on net earnings, as they are a key input to the calculation of depletion expense. The Company assesses property, plant and equipment for impairment discounted at rates currently ranging from 10% to 12% whenever events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low commodity prices for an extended period, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the specific assets at the CGU level. CRUDE OIL AND NATURAL GAS RESERVES B) Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties, interpretations, and judgements. The Company expects that, over time, its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. Reserve estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion, depreciation and amortization and for determining potential asset impairment. For example, a revision to the proved reserve estimates would result in a higher or lower depletion, depreciation and amortization charge to net earnings. Downward revisions to reserve estimates may also result in an impairment of E&E and property, plant and equipment carrying amounts. C) The Company is required to recognize a liability for ARO associated with its property, plant and equipment. An ARO liability associated with the retirement of a tangible long-lived asset is recognized to the extent of a legal obligation resulting from an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount. These individual assumptions can be subject to change. ASSET RETIREMENT OBLIGATIONS The estimated present values of ARO related to long-term assets are recognized as a liability in the period in which they are incurred. The provision for the ARO is estimated by discounting the expected future cash flows to settle the ARO at the Company’s weighted average credit-adjusted risk-free interest rate, which is currently 4.6%. Subsequent to initial measurement, the ARO is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes in discount rates or estimated future cash flows are capitalized to or derecognized from property, plant and equipment. Changes in estimates would impact accretion and depletion expense in net earnings. In addition, differences between actual and estimated costs to settle the ARO, timing of cash flows to settle the obligation and future inflation rates may result in gains or losses on the final settlement of the ARO. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 49 49 15-03-12 6:20 PM INCOME TAXES RISK MANAGEMENT ACTIVITIES D) The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated income tax effects of temporary differences in the carrying value of assets and liabilities in the consolidated financial statements and their respective tax bases, using income tax rates substantively enacted as at the date of the balance sheet. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets.There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes liabilities for potential tax audit issues based on assessments of whether additional taxes will likely be due. E) The Company uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material. F) Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties, together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation and amortization expense and impairment tests. PURCHASE PRICE ALLOCATIONS The Company has made various assumptions in determining the fair values of the acquired assets and liabilities. The most significant assumptions and judgements relate to the estimation of the fair value of the crude oil and natural gas properties. To determine the fair value of these properties, the Company estimates crude oil and natural gas reserves. Reserve estimates are based on the work performed by the Company’s internal engineers and outside consultants. The judgements associated with these estimated reserves are described above in “Crude Oil and Natural Gas Reserves”. Estimates of future prices are based on prices derived from price forecasts among industry analysts and internal assessments. The Company applies estimated future prices to the estimated reserves quantities acquired, and estimates future operating and development costs, to arrive at estimated future net revenues for the properties acquired. G) The Company has made various assumptions in estimating the fair values of stock options granted including expected volatility, expected exercise behavior and future forfeiture rates. At each period end, stock options outstanding are remeasured for subsequent changes in the fair value of the liability. SHARE-BASED COMPENSATION CHANGES IN ACCOUNTING POLICIES Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued in November, 2013. IFRS 9 replaced the sections of IAS 39 “Financial Instruments: Recognition and Measurement” that relate to the classification and measurement of financial instruments and hedge accounting. IFRS 9 replaced the multiple classification and measurement models for financial assets with a new model that has only two measurement categories: amortized cost and fair value through profit or loss. This determination is made at initial recognition. For financial liabilities, the new standard retained most of the IAS 39 requirements. The main change arose in cases where the Company chose to designate a financial liability as fair value through profit or loss. In these situations, the portion of the fair value change related to the Company’s own credit risk is recognized in other comprehensive income rather than net earnings. As a result of adopting IFRS 9, all of the Company’s financial assets as at December 31, 2013 were reclassified from loans and receivables at amortized cost to financial assets at amortized cost.There were no changes to the classifications of the Company’s financial liabilities. In addition, there were no changes in the carrying values of the Company’s financial instruments as a result of the adoption of IFRS 9. The classification and measurement guidance was adopted retrospectively in accordance with the transition provisions of IFRS 9. 50 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 50 15-03-12 6:20 PM The Company also adopted the new hedge accounting guidance in IFRS 9. The new hedge accounting guidance replaced strict quantitative tests of effectiveness with less restrictive assessments of how well the hedging instrument accomplishes the Company’s risk management objectives for financial and non-financial risk exposures. IFRS 9 also allows the Company to hedge risk components of non-financial items which meet certain measurability or identifiable characteristics. Upon adoption of IFRS 9, all of the Company’s existing hedging relationships that qualified for hedge accounting under IAS 39 were reassessed with respect to the new hedge accounting requirements in IFRS 9. The hedging relationships were continued under IFRS 9. The hedge accounting requirements in IFRS 9 were applied prospectively in accordance with the transition provisions of IFRS 9. After adoption of IFRS 9, the Company’s accounting policies are substantially the same as at December 31, 2013, except for the change in financial asset categories as discussed above. Effective January 1, 2014, the Company adopted an amendment to IAS 32 “Financial instruments: Presentation” relating to offsetting financial assets and financial liabilities. This amendment clarifies that the right of set-off must not be contingent on a future event. The amendment did not have a significant impact on the Company’s consolidated financial statements. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. The new standard is required to be adopted retrospectively effective January 1, 2017, with earlier adoption permitted. The Company is currently assessing the impact of IFRS 15 on its consolidated financial statements. In May 2014 the IASB issued an amendment to IFRS 11 “Joint Arrangements” to clarify the accounting treatment when an entity acquires interests in joint ventures and joint operations. The amendment requires these acquisitions to be accounted for as business combinations. This amendment is effective January 1, 2016 and is to be applied prospectively. Adoption of this amended standard is not expected to result in a significant impact in the presentation of the Company’s consolidated financial statements. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The amendments are effective January 1, 2018. The Company is currently assessing the impact of this amendment on its consolidated financial statements. CONTROL ENVIRONMENT The Company’s management, including the President and the Chief Financial Officer and Senior Vice-President, Finance, evaluated the effectiveness of disclosure controls and procedures as at December 31, 2014, and concluded that disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual filings and other reports filed with securities regulatory authorities in Canada and the United States is recorded, processed, summarized and reported within the time periods specified and such information is accumulated and communicated to the Company’s management to allow timely decisions regarding required disclosures. The Company’s management also performed an assessment of internal control over financial reporting as at December 31, 2014, and concluded that internal control over financial reporting is effective. Further, there were no changes in the Company’s internal control over financial reporting during 2014 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting. While the Company’s management believes that the Company’s disclosure controls and procedures and internal control over financial reporting provide a reasonable level of assurance they are effective, they recognize that all control systems have inherent limitations. Because of its inherent limitations, the Company’s control systems may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 51 51 15-03-12 6:20 PM OUTLOOK The Company continues to implement its strategy of maintaining a large portfolio of varied projects, which the Company believes will enable it, over an extended period of time, to provide consistent growth in production and create shareholder value. Annual budgets are developed, scrutinized throughout the year and revised if necessary in the context of targeted financial ratios, project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas. Included in the Company’s original 2015 budget was approximately $2,000 million of capital flexibility, which allows the Company to reallocate capital over 2015 as required. In response to declining commodity prices, in December 2014 the Company proactively reviewed its capital allocation strategy and in January 2015 announced that it would access this capital flexibility to reduce capital spending by approximately $2,400 million. Subsequently, capital expenditure guidance for 2015 has been further reduced by $150 million as a result of the reduction in scope of the originally planned 2015 Horizon maintenance turnaround from 35 days to 6 days. The Company has significant additional capital flexibility in 2015 to further curtail capital spending if required or increase capital spending if commodity prices strengthen. As a result of the reduced capital expenditure targets for 2015, the Company revised its 2015 targeted annual production levels before royalties to average between 562,000 bbl/d and 602,000 bbl/d of crude oil and NGLs and between 1,730 MMcf/d and 1,770 MMcf/d of natural gas. Capital expenditures in 2015 are currently targeted to be as follows: ($ millions) Exploration and Production North America natural gas and NGLs North America crude oil International crude oil Thermal In Situ Oil Sands Primrose and future Kirby South Kirby North Phase 1 Net acquisitions, Midstream and other Total Exploration and Production Oil Sands Mining and Upgrading Project Capital Directive 74 Phase 2A Phase 2B Phase 3 Owner’s Costs and Other Total Project Capital Technology and Phase 4 Sustaining capital Turnarounds and reclamation Capitalized interest and other Total Oil Sands Mining and Upgrading Total 2015 490 980 1,165 300 55 105 70 3,165 55 45 1,210 550 340 2,200 20 300 10 345 2,875 6,040 $ $ $ $ $ 52 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 52 15-03-12 6:20 PM SENSITIVITY ANALYSIS The following table is indicative of the annualized sensitivities of cash flow from operations and net earnings from changes in certain key variables. The analysis is based on business conditions and sales volumes during the fourth quarter of 2014, excluding mark-to-market gains (losses) on risk management activities and is not necessarily indicative of future results. Each separate line item in the sensitivity analysis shows the effect of a change in that variable only with all other variables being held constant. Price changes Crude oil – WTI US$1.00/bbl (1) Excluding financial derivatives Including financial derivatives Natural gas – AECO C$0.10/Mcf (1) Volume changes Crude oil – 10,000 bbl/d Natural gas – 10 MMcf/d Foreign currency rate change $0.01 change in US$ (1) Including financial derivatives Interest rate change – 1% Cash flow from operations ($ millions) Cash flow from operations (per common share, basic) Net earnings ($ millions) Net earnings (per common share, basic) $ $ $ $ $ $ $ 156 $ 142 $ 38 $ 121 $ 7 $ 0.14 $ 0.13 $ 0.03 $ 0.11 $ 0.01 $ 156 $ 142 $ 38 $ 78 $ 1 $ 112 – 115 $ 22 $ 0.10 $ 0.02 $ 51 – 52 $ 22 $ 0.14 0.13 0.03 0.07 – 0.05 0.02 (1) For details of financial instruments in place, refer to note 17 to the Company’s consolidated financial statements as at December 31, 2014. DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES Crude oil and NGLs (bbl/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total Natural gas (MMcf/d) North America North Sea Offshore Africa Total Barrels of oil equivalent (BOE/d) North America – Exploration and Production North America – Oil Sands Mining and Upgrading North Sea Offshore Africa Total Q1 Q2 Q3 Q4 2014 2013 2012 348,187 400,154 404,114 409,976 390,814 343,699 326,829 113,095 16,715 10,791 488,788 119,236 12,615 13,164 545,169 82,012 18,197 13,684 518,007 128,090 21,927 12,047 572,040 110,571 17,380 12,429 531,194 100,284 18,334 15,923 478,240 86,077 19,824 18,648 451,378 1,147 7 21 1,175 1,606 5 23 1,634 1,644 7 23 1,674 1,705 10 18 1,733 1,527 7 21 1,555 1,130 4 24 1,158 1,198 2 20 1,220 539,246 667,737 678,062 694,138 645,227 531,961 526,460 113,095 119,236 82,012 128,090 110,571 100,284 86,077 17,960 14,346 684,647 13,502 16,996 817,471 19,320 17,537 796,931 23,664 15,028 860,920 18,629 15,983 790,410 19,029 19,888 671,162 20,151 21,977 654,665 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 53 53 15-03-12 6:20 PM PER UNIT RESULTS – EXPLORATION AND PRODUCTION Crude oil and NGLs ($/bbl) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Natural gas ($/Mcf) (1) Sales price (2) Transportation Realized sales price, net of transportation Royalties Production expense Netback Barrels of oil equivalent ($/BOE) (1) Q1 Q2 Q3 Q4 2014 2013 2012 $ 79.68 $ 87.03 $ 79.99 $ 62.80 $ 77.04 $ 73.81 $ 72.44 2.49 77.19 14.05 2.74 84.29 15.62 2.32 77.67 13.66 2.15 60.65 9.05 2.41 74.63 12.99 2.22 71.59 11.13 2.20 70.24 10.67 19.18 16.11 $ 43.96 $ 49.34 $ 48.02 $ 32.91 $ 43.39 $ 43.32 $ 43.46 15.99 18.25 19.33 18.69 17.14 $ 5.69 $ 5.06 $ 4.54 $ 4.32 $ 4.83 $ 3.58 $ 0.30 5.39 0.62 1.61 3.16 $ 0.26 4.80 0.41 1.52 2.87 $ 0.26 4.28 0.32 1.45 2.51 $ 0.28 4.04 0.24 1.39 2.41 $ 0.27 4.56 0.38 1.48 2.70 $ 0.28 3.30 0.18 1.42 1.70 $ $ 2.70 0.26 2.44 0.09 1.31 1.04 Sales price (2) $ 63.14 $ 64.69 $ 59.56 $ 48.23 $ 58.48 $ 56.46 $ 52.85 Transportation Realized sales price, net of transportation Royalties 2.29 60.85 10.42 2.35 62.34 10.49 2.08 57.48 9.12 2.05 46.18 6.10 2.18 56.30 8.90 2.10 54.36 7.74 2.04 50.81 7.07 Production expense Netback 15.82 13.14 $ 34.61 $ 36.50 $ 35.21 $ 25.42 $ 32.73 $ 32.38 $ 30.60 13.15 14.67 14.66 15.35 14.24 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Net of blending costs and excluding risk management activities. PER UNIT RESULTS – OIL SANDS MINING AND UPGRADING Crude oil and NGLs ($/bbl) (1) SCO sales price Bitumen royalties (2) Transportation Adjusted cash production costs Netback Q1 Q2 Q3 Q4 2014 2013 2012 $ 107.82 $ 112.69 $ 103.91 $ 79.23 $ 100.27 $ 100.75 $ 90.74 5.06 1.96 41.11 $ 59.69 $ 6.77 1.53 36.61 67.78 $ 7.17 2.28 37.13 57.33 $ 38.69 $ 55.47 $ 53.50 $ 5.11 1.57 40.57 4.44 1.76 34.34 5.77 1.85 37.18 4.34 1.83 42.83 41.74 (1) Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. (2) Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. 54 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 54 15-03-12 6:20 PM TRADING AND SHARE STATISTICS TSX – C$ Trading volume (thousands) Share Price ($/share) High Low Close Market capitalization as at December 31 ($ millions) Shares outstanding (thousands) NYSE – US$ Trading volume (thousands) Share Price ($/share) High Low Close Market capitalization as at December 31 ($ millions) Shares outstanding (thousands) Q1 Q2 Q3 Q4 2014 2013 174,223 127,633 149,886 265,838 717,580 683,003 42.49 $ 49.22 $ 49.57 $ 43.75 $ 49.57 $ 34.72 $ 42.20 $ 42.89 $ 31.00 $ 31.00 $ 42.37 $ 49.03 $ 43.51 $ 35.92 $ 35.92 $ 36.04 28.44 35.94 $ 39,219 $ 39,078 1,091,837 1,087,322 175,885 143,772 149,812 343,052 812,521 645,403 38.44 $ 31.56 $ 46.14 $ 38.23 $ 46.65 $ 38.38 $ 39.12 $ 26.53 $ 46.65 $ 26.53 $ 38.37 $ 45.91 $ 38.84 $ 30.88 $ 30.88 $ 33.92 26.98 33.84 $ $ $ $ $ $ $ 33,716 $ 36,795 1,091,837 1,087,322 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 55 55 15-03-12 6:20 PM MANAGEMENT’S REPORT The accompanying consolidated financial statements and all other information contained elsewhere in this Annual Report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with the accounting policies described in the accompanying notes. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the financial statements have been prepared in accordance with International Financial Reporting Standards appropriate in the circumstances. The financial information presented elsewhere in the Annual Report has been reviewed to ensure consistency with that in the consolidated financial statements. Management maintains appropriate systems of internal control. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized and recorded, assets are safeguarded from loss or unauthorized use and financial records are properly maintained to provide reliable information for preparation of financial statements. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has been engaged, as approved by a vote of the shareholders at the Company’s most recent Annual General Meeting, to audit and provide their independent audit opinions on the following: ■■ ■■ the Company’s consolidated financial statements as at and for the year ended December 31, 2014; and the effectiveness of the Company’s internal control over financial reporting as at December 31, 2014. Their report is presented with the consolidated financial statements. The Board of Directors (the “Board”) is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board exercises this responsibility through the Audit Committee of the Board, which is comprised entirely of independent directors. The Audit Committee meets with management and the independent auditors to satisfy itself that management responsibilities are properly discharged and to review the consolidated financial statements before they are presented to the Board for approval. The consolidated financial statements have been approved by the Board on the recommendation of the Audit Committee. Steve W. Laut President Calgary, Alberta, Canada March 4, 2015 Corey B. Bieber, CA Chief Financial Officer and Senior Vice-President, Finance Murray G. Harris, CA Vice-President, Financial Controller and Horizon Accounting 56 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 56 15-03-12 6:20 PM MANAGEMENT’S ASSESSMENT OF INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a–15(f) and 15d–15(f) under the United States Securities Exchange Act of 1934, as amended. Management, including the Company’s President and the Company’s Chief Financial Officer and Senior Vice-President, Finance, performed an assessment of the Company’s internal control over financial reporting based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of theTreadway Commission (“COSO”). Based on the assessment, management has concluded that the Company’s internal control over financial reporting is effective as at December 31, 2014. Management recognizes that all internal control systems have inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. PricewaterhouseCoopers LLP, an independent firm of Chartered Accountants, has provided an opinion on the Company’s internal control over financial reporting as at December 31, 2014, as stated in their Auditor’s Report. Steve W. Laut President Calgary, Alberta, Canada March 4, 2015 Corey B. Bieber, CA Chief Financial Officer and Senior Vice-President, Finance Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 57 57 15-03-12 6:20 PM INDEPENDENT AUDITOR’S REPORT TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED We have completed integrated audits of Canadian Natural Resources Limited’s 2014, 2013, and 2012 consolidated financial statements and its internal control over financial reporting as at December 31, 2014. Our opinions, based on our audits are presented below. REPORT ON THE CONSOLIDATED FINANCIAL STATEMENTS We have audited the accompanying consolidated financial statements of Canadian Natural Resources Limited, which comprise the consolidated balance sheets as at December 31, 2014 and December 31, 2013 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2014, and the related notes. MANAGEMENT’S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements.The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. OPINION In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Canadian Natural Resources Limited as at December 31, 2014 and December 31, 2013 and its financial performance and its cash flows for each of the three years in the period ended December 31, 2014 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING We have also audited Canadian Natural Resources Limited’s internal control over financial reporting as at December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). MANAGEMENT’S RESPONSIBILITY FOR INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report. 58 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 58 15-03-12 6:20 PM AUDITOR’S RESPONSIBILITY Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our audit opinion on Canadian Natural Resources Limited’s internal control over financial reporting. DEFINITION OF INTERNAL CONTROL OVER FINANCIAL REPORTING A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. INHERENT LIMITATIONS Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate. OPINION In our opinion, Canadian Natural Resources Limited maintained, in all material respects, effective internal control over financial reporting as at December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. Chartered Accountants Calgary, Alberta, Canada March 4, 2015 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 59 59 15-03-12 6:20 PM CONSOLIDATED BALANCE SHEETS As at December 31 (millions of Canadian dollars) ASSETS Current assets Cash and cash equivalents Accounts receivable Current income taxes Inventory Prepaids and other Current portion of other long-term assets Exploration and evaluation assets Property, plant and equipment Other long-term assets LIABILITIES Current liabilities Accounts payable Accrued liabilities Current income taxes Current portion of long-term debt Current portion of other long-term liabilities Long-term debt Other long-term liabilities Deferred income taxes SHAREHOLDERS’ EQUITY Share capital Retained earnings Accumulated other comprehensive income Commitments and contingencies (note 18). Approved by the Board of Directors on March 4, 2015 Note 2014 2013 $ 25 $ $ $ 5 8 6 7 8 9 10 9 10 11 12 13 1,889 228 665 172 510 3,489 3,557 52,480 674 60,200 $ 564 $ 3,279 – 980 319 5,142 13,022 4,175 8,970 31,309 4,432 24,408 51 28,891 $ 60,200 $ 16 1,427 – 632 141 – 2,216 2,609 46,487 442 51,754 637 2,519 359 1,444 275 5,234 8,217 4,348 8,183 25,982 3,854 21,876 42 25,772 51,754 Catherine M. Best Chair of the Audit Committee and Director N. Murray Edwards Chairman of the Board of Directors and Director 60 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 60 15-03-12 6:20 PM CONSOLIDATED STATEMENTS OF EARNINGS For the years ended December 31 (millions of Canadian dollars, except per common share amounts) Note 2014 2013 Product sales Less: royalties Revenue Expenses Production Transportation and blending Depletion, depreciation and amortization Administration Share-based compensation Asset retirement obligation accretion Interest and other financing expense Risk management activities Foreign exchange loss (gain) Gain on corporate acquisitions/disposition of properties Equity loss from investment Earnings before taxes Current income tax expense Deferred income tax expense (recovery) Net earnings Net earnings per common share Basic Diluted $ 21,301 $ (2,438) 18,863 17,945 $ (1,800) 16,145 5,265 3,232 4,880 367 66 193 323 (800) 303 (137) 8 13,700 5,163 427 807 4,559 2,938 4,844 335 135 171 279 (77) 210 (289) 4 13,109 3,036 735 31 7 10 10 16 17 6, 7 8 11 11 2012 16,195 (1,606) 14,589 4,249 2,752 4,328 270 (214) 151 364 120 (49) – 9 11,980 2,609 747 (30) $ 3,929 $ 2,270 $ 1,892 15 $ 15 $ 3.60 $ 3.58 $ 2.08 $ 2.08 $ 1.72 1.72 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME For the years ended December 31 (millions of Canadian dollars) Net earnings Items that may be reclassified subsequently to net earnings Net change in derivative financial instruments designated as cash flow hedges Unrealized income (loss), net of taxes of $nil (2013 – $nil, 2012 – $4 million) Reclassification to net earnings, net of taxes of $1 million (2013 – $nil, 2012 – $nil) 2014 2013 $ 3,929 $ 2,270 $ 5 8 13 (4) (1) (5) Foreign currency translation adjustment Translation of net investment Other comprehensive income (loss), net of taxes Comprehensive income (4) 9 3,938 $ (11) (16) 2,254 $ $ 2012 1,892 31 (7) 24 8 32 1,924 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 61 61 15-03-12 6:20 PM CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY For the years ended December 31 (millions of Canadian dollars) Share capital Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year Retained earnings Balance – beginning of year Net earnings Purchase of common shares under Normal Course Issuer Bid Dividends on common shares Balance – end of year Accumulated other comprehensive income Balance – beginning of year Other comprehensive income (loss), net of taxes Balance – end of year Shareholders’ equity Note 12 12 12 13 2014 2013 2012 $ 3,854 $ 3,709 $ 488 129 (39) 4,432 21,876 3,929 (414) (983) 24,408 42 9 130 50 (35) 3,854 20,516 2,270 (285) (625) 21,876 58 (16) 51 28,891 $ 42 25,772 $ $ 3,507 194 45 (37) 3,709 19,365 1,892 (281) (460) 20,516 26 32 58 24,283 62 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 62 15-03-12 6:20 PM CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31 (millions of Canadian dollars) Operating activities Net earnings Non-cash items Depletion, depreciation and amortization Share-based compensation Asset retirement obligation accretion Unrealized risk management (gain) loss Unrealized foreign exchange loss Realized foreign exchange loss (gain) on repayment of US dollar debt securities Equity loss from investment Deferred income tax expense (recovery) Gain on corporate acquisitions/disposition of properties Current income tax on disposition of properties Other Abandonment expenditures Net change in non-cash working capital Financing activities Issue of bank credit facilities and commercial paper, net Issue of medium-term notes, net Issue (repayment) of US dollar debt securities, net Issue of common shares on exercise of stock options Purchase of common shares under Normal Course Issuer Bid Dividends on common shares Net change in non-cash working capital Investing activities Net (expenditures) proceeds on exploration and evaluation assets Net expenditures on property, plant and equipment Current income tax on disposition of properties Investment in other long-term assets Net change in non-cash working capital Increase (decrease) in cash and cash equivalents Cash and cash equivalents – beginning of year Cash and cash equivalents – end of year Interest paid Income taxes paid Note 2014 2013 2012 $ 3,929 $ 2,270 $ 1,892 4,880 66 193 (451) 256 36 8 807 (137) – (38) (346) (744) 8,459 1,195 992 1,482 488 (453) (955) (22) 2,727 (1,190) (10,208) – (113) 334 (11,177) 9 16 25 $ 521 $ 792 $ $ $ $ 19 9 19 19 19 19 4,844 4,328 135 171 39 226 (12) 4 31 (289) 58 (19) (207) (33) 7,218 803 98 (398) 130 (320) (523) (23) (233) 144 (7,211) (58) – 119 (7,006) (21) 37 16 $ 460 $ 357 $ (214) 151 (42) 129 (210) 9 (30) – – (47) (204) 447 6,209 172 498 (344) 194 (318) (444) (37) (279) (309) (5,795) – 2 175 (5,927) 3 34 37 464 639 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 63 63 15-03-12 6:20 PM NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (tabular amounts in millions of Canadian dollars, unless otherwise stated) 1. ACCOUNTING POLICIES Canadian Natural Resources Limited (the “Company”) is a senior independent crude oil and natural gas exploration, development and production company. The Company’s exploration and production operations are focused in North America, largely in Western Canada; the United Kingdom (“UK”) portion of the North Sea; and Côte d’Ivoire, Gabon, and South Africa in Offshore Africa. The Horizon Oil Sands Mining and Upgrading segment (“Horizon”) produces synthetic crude oil through bitumen mining and upgrading operations. Within Western Canada, the Company maintains certain midstream activities that include pipeline operations, an electricity co-generation system and an investment in the North West Redwater Partnership (“Redwater Partnership”), a general partnership formed in the Province of Alberta. The Company was incorporated in Alberta, Canada. The address of its registered office is 2100, 855-2 Street S.W., Calgary, Alberta, Canada. The Company’s consolidated financial statements and the related notes have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The accounting policies adopted by the Company under IFRS are set out below. The Company has consistently applied the same accounting policies throughout all periods presented, except where IFRS permits new accounting standards to be adopted prospectively (see note 2). (A) PRINCIPLES OF CONSOLIDATION The consolidated financial statements have been prepared under the historical cost basis, unless otherwise required. The consolidated financial statements include the accounts of the Company and all of its subsidiary companies and wholly owned partnerships. Subsidiaries are all entities over which the Company has control. Subsidiaries are consolidated from the date on which the Company obtains control. They are deconsolidated from the date that control ceases. Certain of the Company’s activities are conducted through joint arrangements in which two or more parties have joint control. Where the Company has a direct ownership interest the liabilities (a “joint operation”), the assets, liabilities, revenue and expenses related to the joint operation are included in the consolidated financial statements in proportion to the Company’s interest. Where the Company has an interest in jointly controlled entities (a “joint venture”), it uses the equity method of accounting. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of the joint venture’s income or loss, less distributions received. in jointly controlled assets and obligations for Joint ventures accounted for using the equity method of accounting are tested for impairment whenever objective evidence indicates that the carrying amount of the investment may not be recoverable. Indications of impairment include a history of losses, significant capital expenditure overruns, liquidity concerns, financial restructuring of the investee or significant adverse changes in the technological, economic or legal environment. The amount of the impairment is measured as the difference between the carrying amount of the investment and the higher of its fair value less costs of disposal and its value in use. Impairment losses are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. SEGMENTED INFORMATION CASH AND CASH EQUIVALENTS (B) Operating segments have been determined based on the nature of the Company’s activities and the geographic locations in which the Company operates, and are consistent with the level of information regularly provided to and reviewed by the Company’s chief operating decision makers. (C) Cash comprises cash on hand and demand deposits. Other investments (term deposits and certificates of deposit) with an original term to maturity at purchase of three months or less are reported as cash equivalents in the consolidated balance sheets. INVENTORY (D) Inventory is primarily comprised of product inventory and materials and supplies. Product inventory is comprised of crude oil held for sale, including pipeline linefill and crude oil stored in floating production, storage and offloading vessels. Inventories are carried at the lower of cost and net realizable value. Cost consists of purchase costs, direct production costs, directly attributable overhead and depletion, depreciation and amortization and is determined on a first-in, first-out basis. Net realizable value for product inventory is determined by reference to forward prices, and for materials and supplies is based on current market prices as at the date of the consolidated balance sheets. 64 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 64 15-03-12 6:20 PM EXPLORATION AND EVALUATION ASSETS (E) Exploration and evaluation (“E&E”) assets consist of the Company’s crude oil and natural gas exploration projects that are pending the determination of proved reserves. E&E costs are initially capitalized and include costs directly associated with the acquisition of licenses, technical services and studies, seismic acquisition, exploration drilling and evaluation, overhead and administration expenses, and the estimate of any asset retirement costs. E&E costs do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore an area. These costs are recognized in net earnings. Once the technical feasibility and commercial viability of E&E assets are determined and a development decision is made by management, the E&E assets are tested for impairment upon reclassification to property, plant and equipment. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when an assessment of proved reserves is made. E&E assets are also tested for impairment when facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount, by comparing the relevant costs to the fair value of Cash Generating Units (“CGUs”), aggregated at the segment level. Indications of impairment include leases approaching expiry, the existence of low benchmark commodity prices for an extended period of time, significant downward revisions in estimated probable reserves volumes, significant increases in estimated future exploration or development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. PROPERTY, PLANT AND EQUIPMENT (F) Property, plant and equipment is measured at cost less accumulated depletion and depreciation and impairment provisions. Assets under construction are not depleted or depreciated until available for their intended use. The capitalized value of a finance lease is included in property, plant and equipment. Exploration and Production The cost of an asset comprises its acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Property acquisition costs are comprised of the aggregate amount paid and the fair value of any other consideration given to acquire the asset. When significant components of an item of property, plant and equipment, including crude oil and natural gas interests, have different useful lives, they are accounted for separately. Crude oil and natural gas properties are depleted using the unit-of-production method over proved reserves, except for major components, which are depreciated using a straight-line method over their estimated useful lives. The unit-of-production depletion rate takes into account expenditures incurred to date, together with future development expenditures required to develop proved reserves. Oil Sands Mining and Upgrading Capitalized costs for the Oil Sands Mining and Upgrading segment are reported separately from the Company’s North America Exploration and Production segment. Capitalized costs include acquisition costs, construction and development costs, costs directly attributable to bringing the asset into operation, the estimate of any asset retirement costs, and applicable borrowing costs. Mine-related costs are depleted using the unit-of-production method based on Horizon proved reserves. Costs of the upgrader and related infrastructure located on the Horizon site are depreciated on the unit-of-production method based on productive capacity of the upgrader and related infrastructure. Other equipment is depreciated on a straight-line basis over its estimated useful life ranging from 2 to 15 years. Midstream and Head Office The Company capitalizes all costs that expand the capacity or extend the useful life of the midstream and head office assets. Midstream assets are depreciated on a straight-line basis over their estimated useful lives ranging from 5 to 30 years. Head office assets are depreciated on a declining balance basis. Useful lives The depletion rates and expected useful lives of property, plant and equipment are reviewed on an annual basis, with changes in depletion rates and useful lives accounted for prospectively. Derecognition An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is recognized in net earnings within depletion, depreciation and amortization. Major maintenance expenditures Inspection costs associated with major maintenance turnarounds are capitalized and depreciated over the period to the next major maintenance turnaround. All other maintenance costs are expensed as incurred. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 65 65 15-03-12 6:20 PM Impairment The Company assesses property, plant and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or group of assets may not be recoverable. Indications of impairment include the existence of low benchmark commodity prices for an extended period of time, significant downward revisions of estimated reserves volumes, significant increases in estimated future development expenditures, or significant adverse changes in the applicable legislative or regulatory frameworks. If an indication of impairment exists, the Company performs an impairment test related to the assets. Individual assets are grouped for impairment assessment purposes into CGUs, which are the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. CAPITALIZED BORROWING COSTS In subsequent periods, an assessment is made at each reporting date to determine whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is re-estimated and the net carrying amount of the asset is increased to its revised recoverable amount. The revised recoverable amount cannot exceed the carrying amount that would have been determined, net of depletion, had no impairment loss been recognized for the asset in prior periods. A reversal of impairment is recognized in net earnings. After a reversal, the depletion charge is adjusted in future periods to allocate the asset’s revised carrying amount over its remaining useful life. (G) BUSINESS COMBINATIONS Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair value at the date of the acquisition. Any excess of the consideration paid over the fair value of the net assets acquired is recognized as an asset. Any excess of the fair value of the net assets acquired over the consideration paid is recognized in net earnings. (H) OVERBURDEN REMOVAL COSTS Overburden removal costs incurred during the initial development of a mine at Horizon are capitalized to property, plant and equipment. Overburden removal costs incurred during the production of a mine are included in the cost of inventory, unless the overburden removal activity has resulted in a probable inflow of future economic benefits to the Company, in which case the costs are capitalized to property, plant and equipment. Capitalized overburden removal costs are depleted over the life of the mining reserves that directly benefit from the overburden removal activity. (I) Borrowing costs attributable to the acquisition, construction or production of qualifying assets are capitalized to the cost of those assets until such time as the assets are substantially available for their intended use. Qualifying assets are comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings. (J) Finance leases, which transfer substantially all of the risks and rewards incidental to ownership of the leased item to the Company, are capitalized at the commencement of the lease term at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are recognized in net earnings over the lease term. (K) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on all of its property, plant and equipment based on current legislation and industry operating practices. Provisions for asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Provisions are measured at the present value of management’s best estimate of expenditures required to settle the obligation as at the date of the balance sheet. Subsequent to the initial measurement, the obligation is adjusted to reflect the passage of time, changes in credit adjusted interest rates, and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as asset retirement obligation accretion expense whereas changes due to discount rates or estimated future cash flows are capitalized to or derecognized from property, plant, and equipment. Actual costs incurred upon settlement of the asset retirement obligation are charged against the provision. FOREIGN CURRENCY TRANSLATION (L) Functional and presentation currency Items included in the financial statements of the Company’s subsidiary companies and partnerships are measured using the currency of the primary economic environment in which the subsidiary operates (the “functional currency”). The consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. LEASES The assets and liabilities of subsidiaries that have a functional currency different from that of the Company are translated into Canadian dollars at the closing rate at the date of the balance sheet, and revenue and expenses are translated at the average rate for the period. Cumulative foreign currency translation adjustments are recognized in other comprehensive income. When the Company disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income related to the foreign operation are recognized in net earnings. 66 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 66 15-03-12 6:20 PM Transactions and balances Foreign currency transactions are translated into the functional currency of the Company and its subsidiaries and partnerships using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at balance sheet date exchange rates of monetary assets and liabilities denominated in currencies other than the functional currency are recognized in net earnings. (M) REVENUE RECOGNITION AND COSTS OF GOODS SOLD Revenue from the sale of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Revenue represents the Company’s share net of royalty payments to governments and other mineral interest owners. Related costs of goods sold are comprised of production, transportation and blending, and depletion, depreciation and amortization expenses. These amounts have been separately presented in the consolidated statements of earnings. (N) PRODUCTION SHARING CONTRACTS Production generated from Côte d’Ivoire and Gabon in Offshore Africa is shared under the terms of various Production Sharing Contracts (“PSCs”). Product sales are divided into cost recovery oil and profit oil. Cost recovery oil allows the Company to recover its capital and production costs and the costs carried by the Company on behalf of the respective Government State Oil Companies (the “Governments”). Profit oil is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Governments. The Governments’ share of profit oil attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the terms of the respective PSCs. (O) INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying amount of assets and liabilities in the consolidated financial statements and their respective tax bases. Deferred income tax assets and liabilities are calculated using the substantively enacted income tax rates that are expected to apply when the asset or liability is recovered. Deferred income tax assets or liabilities are not recognized when they arise on the initial recognition of an asset or liability in a transaction (other than in a business combination) that, at the time of the transaction, affects neither accounting nor taxable profit. Deferred income tax assets or liabilities are also not recognized on possible future distributions of retained earnings of subsidiaries where the timing of the distribution can be controlled by the Company and it is probable that a distribution will not be made in the foreseeable future, or when distributions can be made without incurring income taxes. Deferred income tax assets for deductible temporary differences and tax loss carryforwards are recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. The carrying amount of deferred income tax assets is reviewed at each reporting date, and is reduced if it is no longer probable that sufficient future taxable profits will be available against which the temporary differences or tax loss carryforwards can be utilized. Current income tax is calculated based on net earnings for the period, adjusted for items that are non-taxable or taxed in different periods, using income tax rates that are substantively enacted at each reporting date. Income taxes are recognized in net earnings or other comprehensive income, consistent with the items to which they relate. SHARE-BASED COMPENSATION (P) The Company’s Stock Option Plan (the “Option Plan”) provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered. The liability for awards granted to employees is initially measured based on the grant date fair value of the awards and the number of awards expected to vest. The awards are re-measured each reporting period for subsequent changes in the fair value of the liability. Fair value is determined using the Black-Scholes valuation model. Expected volatility is estimated based on historic results. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by the employee and any previously recognized liability associated with the stock options are recorded as share capital. The unamortized costs of employer contributions to the Company’s share bonus program are included in other long-term assets. (Q) The Company classifies its financial instruments into one of the following categories: financial assets at amortized cost; financial liabilities at amortized cost; and fair value through profit or loss. All financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods is dependent on the classification of the respective financial instrument. FINANCIAL INSTRUMENTS Fair value through profit or loss financial instruments are subsequently measured at fair value with changes in fair value recognized in net earnings. All other categories of financial instruments are measured at amortized cost using the effective interest method. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:47 25079_CNR_2014_AR_BOOK.indb 67 67 15-03-12 6:20 PM Cash, cash equivalents, accounts receivable and certain other long-term assets are classified as financial assets at amortized cost since it is the Company’s intention to hold these assets to maturity and the related cash flows are mainly payments of principal and interest. Accounts payable, accrued liabilities, certain other long-term liabilities, and long-term debt are classified as financial liabilities at amortized cost. Risk management assets and liabilities are classified as fair value through profit or loss. Financial assets and liabilities are also categorized using a three-level hierarchy that reflects the significance of the inputs used in making fair value measurements for these assets and liabilities. The fair values of financial assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Fair values of financial assets and liabilities in Level 2 are based on inputs other than Level 1 quoted prices that are observable for the asset or liability either directly (as prices) or indirectly (derived from prices). The fair values of Level 3 financial assets and liabilities are not based on observable market data. The disclosure of the fair value hierarchy excludes financial assets and liabilities where book value approximates fair value due to the liquid nature of the asset or liability. Transaction costs in respect of financial instruments at fair value through profit or loss are recognized in net earnings.Transaction costs in respect of other financial instruments are included in the initial measurement of the financial instrument. Impairment of financial assets At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, an impairment loss is recognized. RISK MANAGEMENT ACTIVITIES Impairment losses on financial assets carried at amortized cost are calculated as the difference between the amortized cost of the financial asset and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized. (R) The Company uses derivative financial instruments to manage its commodity price, foreign currency and interest rate exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. All derivative financial instruments are recognized in the consolidated balance sheets at their estimated fair value. The estimated fair value of derivative financial instruments has been determined based on appropriate internal valuation methodologies and/or third party indications. Fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows, discount rates and credit risk. In determining these assumptions, the Company primarily relied on external, readily-observable market inputs including quoted commodity prices and volatility, interest rate yield curves, and foreign exchange rates. The carrying amount of a risk management liability is adjusted for the Company’s own credit risk. The Company documents all derivative financial instruments that are formally designated as hedging transactions at the inception of the hedging relationship, in accordance with the Company’s risk management policies. The effectiveness of the hedging relationship is evaluated, both at inception of the hedge and on an ongoing basis. The Company periodically enters into commodity price contracts to manage anticipated sales and purchases of crude oil and natural gas in order to protect its cash flow for its capital expenditure programs. The effective portion of changes in the fair value of derivative commodity price contracts formally designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to risk management activities in net earnings in the same period or periods in which the commodity is sold or purchased. The ineffective portion of changes in the fair value of these designated contracts is recognized in risk management activities in net earnings. All changes in the fair value of non-designated crude oil and natural gas commodity price contracts are recognized in risk management activities in net earnings. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on certain of its long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. Changes in the fair value of interest rate swap contracts designated as fair value hedges and corresponding changes in the fair value of the hedged long-term debt are recognized in interest expense in net earnings. Changes in the fair value of non-designated interest rate swap contracts are recognized in risk management activities in net earnings. Cross currency swap contracts are periodically used to manage currency exposure on US dollar denominated long-term debt. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. Changes in the fair value of the foreign exchange component of cross currency swap contracts designated as cash flow hedges related to the notional principal amounts are recognized in foreign exchange gains and losses in net earnings. The effective portion of changes in the fair value of the interest rate component of cross currency swap contracts designated as cash flow hedges is initially recognized in other comprehensive income and is reclassified to interest expense when the hedged item is recognized in net earnings, with the ineffective portion recognized in risk management activities in net earnings. Changes in the fair value of non-designated cross currency swap contracts are recognized in risk management activities in net earnings. 68 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 68 15-03-12 6:20 PM Realized gains or losses on the termination of financial instruments that have been designated as cash flow hedges are deferred under accumulated other comprehensive income and amortized into net earnings in the period in which the underlying hedged items are recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized in net earnings. Realized gains or losses on the termination of financial instruments that have not been designated as hedges are recognized in net earnings. Upon termination of an interest rate swap designated as a fair value hedge, the interest rate swap is derecognized on the consolidated balance sheets and the related long-term debt hedged is no longer revalued for subsequent changes in fair value. The fair value adjustment on the long-term debt at the date of termination of the interest rate swap is amortized to interest expense over the remaining term of the long-term debt. Foreign currency forward contracts are periodically used to manage foreign currency cash requirements. The foreign currency forward contracts involve the purchase or sale of an agreed upon amount of US dollars at a specified future date at forward exchange rates. Changes in the fair value of foreign currency forward contracts designated as cash flow hedges are initially recorded in other comprehensive income and are reclassified to foreign exchange gains and losses when the hedged item is recognized in net earnings. Changes in the fair value of non-designated foreign currency forward contracts are recognized in risk management activities in net earnings. Embedded derivatives are derivatives that are included in a non-derivative host contract. Embedded derivatives are recorded at fair value separately from the host contract when their economic characteristics and risks are not clearly and closely related to the host contract. COMPREHENSIVE INCOME PER COMMON SHARE AMOUNTS (S) Comprehensive income is comprised of the Company’s net earnings and other comprehensive income. Other comprehensive income includes the effective portion of changes in the fair value of derivative financial instruments designated as cash flow hedges and foreign currency translation gains and losses arising from the net investment in foreign operations that do not have a Canadian dollar functional currency. Other comprehensive income is shown net of related income taxes. (T) The Company calculates basic earnings per common share by dividing net earnings by the weighted average number of common shares outstanding during the period. As the Company’s Option Plan allows for the settlement of stock options in either cash or shares at the option of the holder, diluted earnings per common share is calculated using the more dilutive of cash settlement or share settlement under the treasury stock method. (U) Common shares are classified as equity. Costs directly attributable to the issue of new shares or options are included in equity as a deduction from proceeds, net of tax. When the Company acquires its own common shares, share capital is reduced by the average carrying value of the shares purchased. The excess of the purchase price over the average carrying value is recognized as a reduction of retained earnings. Shares are cancelled upon purchase. (V) DIVIDENDS Dividends on common shares are recognized in the Company’s financial statements in the period in which the dividends are approved by the Board of Directors. SHARE CAPITAL 2. CHANGES IN ACCOUNTING POLICIES Effective January 1, 2014, the Company adopted the version of IFRS 9 “Financial Instruments” issued in November 2013. IFRS 9 replaced the sections of IAS 39 “Financial Instruments: Recognition and Measurement” that relate to the classification and measurement of financial instruments and hedge accounting. IFRS 9 replaced the multiple classification and measurement models for financial assets with a new model that has only two measurement categories: amortized cost and fair value through profit or loss. This determination is made at initial recognition. For financial liabilities, the new standard retained most of the IAS 39 requirements. The main change arose in cases where the Company chose to designate a financial liability as fair value through profit or loss. In these situations, the portion of the fair value change related to the Company’s own credit risk is recognized in other comprehensive income rather than net earnings. As a result of adopting IFRS 9, all of the Company’s financial assets as at December 31, 2013 were reclassified from loans and receivables at amortized cost to financial assets at amortized cost.There were no changes to the classifications of the Company’s financial liabilities. In addition, there were no changes in the carrying values of the Company’s financial instruments as a result of the adoption of IFRS 9. The classification and measurement guidance was adopted retrospectively in accordance with the transition provisions of IFRS 9. The Company also adopted the new hedge accounting guidance in IFRS 9. The new hedge accounting guidance replaced strict quantitative tests of effectiveness with less restrictive assessments of how well the hedging instrument accomplishes the Company’s risk management objectives for financial and non-financial risk exposures. IFRS 9 also allows the Company to hedge risk components of non-financial items which meet certain measurability or identifiable characteristics. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 69 69 15-03-12 6:20 PM Upon adoption of IFRS 9, all of the Company’s existing hedging relationships that qualified for hedge accounting under IAS 39 were reassessed with respect to the new hedge accounting requirements in IFRS 9. The hedging relationships were continued under IFRS 9. The hedge accounting requirements in IFRS 9 were applied prospectively in accordance with the transition provisions of IFRS 9. After adoption of IFRS 9, the Company’s accounting policies are substantially the same as at December 31, 2013, except for the change in financial asset categories as discussed above. Effective January 1, 2014, the Company adopted an amendment to IAS 32 “Financial instruments: Presentation” relating to offsetting financial assets and financial liabilities. This amendment clarifies that the right of set-off must not be contingent on a future event. The amendment did not have a significant impact on the Company’s consolidated financial statements. 3. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED In May 2014, the IASB issued IFRS 15 “Revenue from Contracts with Customers” to provide guidance on the recognition of revenue and cash flows arising from an entity’s contracts with customers, and related disclosures. The new standard replaces several existing standards related to recognition of revenue and states that revenue should be recognized as performance obligations related to the goods or services delivered are settled. IFRS 15 also provides revenue accounting guidance for contract modifications and multiple-element contracts and prescribes additional disclosure requirements. The new standard is required to be adopted retrospectively effective January 1, 2017, with earlier adoption permitted. The Company is currently assessing the impact of IFRS 15 on its consolidated financial statements. In May 2014, the IASB issued an amendment to IFRS 11 “Joint Arrangements” to clarify the accounting treatment when an entity acquires interests in joint ventures and joint operations. The amendment requires these acquisitions to be accounted for as business combinations. This amendment is effective January 1, 2016 and is to be applied prospectively. Adoption of this amended standard is not expected to result in a significant impact to the Company’s consolidated financial statements. In July 2014, the IASB issued amendments to IFRS 9 to include accounting guidance to assess and recognize impairment losses on financial assets based on an expected loss model. The amendments are effective January 1, 2018. The Company is currently assessing the impact of this amendment on its consolidated financial statements. 4. CRITICAL ACCOUNTING ESTIMATES AND JUDGEMENTS CRUDE OIL AND NATURAL GAS RESERVES The Company has made estimates, assumptions and judgements regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated financial statements, primarily related to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts. The estimates, assumptions and judgements that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are addressed below. (A) Purchase price allocations, depletion, depreciation and amortization, and amounts used in impairment calculations are based on estimates of crude oil and natural gas reserves. Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties, interpretations and judgements. The Company expects that, over time, its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels, and may be affected by changes in commodity prices. (B) ASSET RETIREMENT OBLIGATIONS The Company provides for asset retirement obligations on its property, plant and equipment based on current legislation and operating practices. Estimated future costs include assumptions of dates of future abandonment and technological advances and estimates of future inflation rates and discount rates. Actual costs may vary from the estimated provision due to changes in environmental legislation, the impact of inflation, changes in technology, changes in operating practices, and changes in the date of abandonment due to changes in reserve life. These differences may have a material impact on the estimated provision. (C) The Company is subject to income taxes in numerous legal jurisdictions. Accounting for income taxes requires the Company to interpret frequently changing laws and regulations, including changing income tax rates, and make certain judgements with respect to the application of tax law, estimating the timing of temporary difference reversals, and estimating the realizability of tax assets. There are many transactions and calculations for which the ultimate tax determination is uncertain. The Company recognizes liabilities for potential tax audit issues based on assessments of whether additional taxes will likely be due. INCOME TAXES 70 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 70 15-03-12 6:20 PM SHARE-BASED COMPENSATION PURCHASE PRICE ALLOCATIONS FAIR VALUE OF DERIVATIVES AND OTHER FINANCIAL INSTRUMENTS (D) The fair value of financial instruments that are not traded in an active market is determined using valuation techniques. The Company uses its judgement to select a variety of methods and make assumptions that are primarily based on market conditions existing at the end of each reporting period.The Company uses directly and indirectly observable inputs in measuring the value of financial instruments that are not traded in active markets, including quoted commodity prices and volatility, interest rate yield curves and foreign exchange rates. (E) Purchase prices related to business combinations are allocated to the underlying acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make estimates, assumptions and judgements regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities, including the fair value of crude oil and natural gas properties together with deferred income tax effects. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future depletion, depreciation, and amortization expense and impairment tests. (F) The Company has made various assumptions in estimating the fair values of the stock options granted under the Option Plan, including expected volatility, expected exercise timing and future forfeiture rates. At each period end, stock options outstanding are remeasured for changes in the fair value of the liability. (G) CGUs are defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgement and interpretations with respect to the integration between assets, the existence of active markets, shared infrastructures, and the way in which management monitors the Company’s operations. (H) The recoverable amount of a CGU or an individual asset has been determined as the higher of the CGU’s or the asset’s fair value less costs of disposal and its value in use. These calculations require the use of estimates and assumptions and are subject to change as new information becomes available including information on future commodity prices, expected production volumes, quantity of reserves, asset retirement obligations, future development and operating costs, discount rates currently ranging from 10% to 12%, and income taxes. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs. (I) Contingencies are subject to measurement uncertainty as the related financial impact will only be confirmed by the outcome of a future event. The assessment of contingencies requires the application of judgements and estimates including the determination of whether a present obligation exists and the reliable estimation of the timing and amount of cash flows required to settle the contingency. IDENTIFICATION OF CGUS IMPAIRMENT OF ASSETS CONTINGENCIES 5. INVENTORY Product inventory Materials and supplies 2014 332 $ 333 665 $ 2013 342 290 632 $ $ As a result of a decline in crude oil prices, the Company recorded a write-down of its product inventory of $70 million from cost to net realizable value as at December 31, 2014 (2013 – $nil). Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 71 71 15-03-12 6:20 PM 6. EXPLORATION AND EVALUATION ASSETS Cost At December 31, 2012 Additions Transfers to property, plant and equipment Disposals Foreign exchange adjustments At December 31, 2013 Additions Transfers to property, plant and equipment Foreign exchange adjustments At December 31, 2014 Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Total $ 2,564 $ – $ 47 $ – $ 2,611 90 (84) – – 2,570 1,103 (247) – – – – – – – 29 – (39) 2 39 87 – – – – – – – – – 3,426 $ $ – – $ 5 131 $ – – $ 119 (84) (39) 2 2,609 1,190 (247) 5 3,557 During 2014, the Company acquired exploration and evaluation assets in connection with the acquisition of certain crude oil and natural gas properties (refer to note 7). During 2013, the Company disposed of a 50% interest in its exploration right in South Africa, for net cash consideration of US$255 million, including a recovery of US$14 million of past incurred costs, resulting in a pre-tax gain on sale of exploration and evaluation property of $224 million ($166 million after-tax). In the event that a commercial crude oil or natural gas discovery occurs on this exploration right, resulting in the exploration right being converted into a production right, an additional cash payment would be due to the Company at such time, amounting to US$450 million for a commercial crude oil discovery and US$120 million for a commercial natural gas discovery. 72 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 72 15-03-12 6:20 PM 7. PROPERTY, PLANT AND EQUIPMENT Cost At December 31, 2012 Additions Transfers from E&E assets Disposals/derecognitions Foreign exchange adjustments and other At December 31, 2013 Additions Transfers from E&E assets Disposals/derecognitions Foreign exchange adjustments and other At December 31, 2014 Accumulated depletion and depreciation At December 31, 2012 Expense Disposals/derecognitions Foreign exchange adjustments and other At December 31, 2013 Expense Disposals/derecognitions Foreign exchange adjustments and other Oil Sands Mining and Upgrading Midstream Head Office Total Exploration and Production Offshore North North Africa Sea America $ 50,324 $ 4,574 $ 3,045 $ 16,963 $ 312 $ 270 $ 75,488 2,772 196 38 7,032 3,630 299 84 (228) – 53,810 6,858 247 (309) – – – 327 5,200 486 – – 496 97 – – 214 3,356 193 – – 309 – (369) – 19,366 2,728 – (146) – $ 60,606 $ 6,182 $ 3,858 $ 21,948 $ $ 24,991 $ 2,709 $ 2,273 $ 1,202 $ 3,551 (228) 1 28,315 3,880 (309) – 548 – 210 3,467 265 – 317 134 – 144 2,551 105 – 234 582 (369) (1) 1,414 596 (146) – – – – 508 62 – – – – 308 45 – 84 (597) 541 82,548 10,372 247 – – 570 $ (1) – (456) 805 352 $ 93,516 103 $ 8 182 $ 31,460 4,844 21 – – 111 9 – – – – 203 25 (1) – (597) 354 36,061 4,880 (456) 551 At December 31, 2014 $ 31,886 $ 4,049 $ 2,890 $ 1,864 $ 120 $ 227 $ 41,036 Net book value - at December 31, 2014 - at December 31, 2013 $ 28,720 $ 2,133 $ 968 $ 20,084 $ $ 25,495 $ 1,733 $ 805 $ 17,952 $ 450 $ 397 $ 125 $ 52,480 105 $ 46,487 Project costs not subject to depletion and depreciation Horizon Kirby Thermal Oil Sands – North Kirby Thermal Oil Sands – South 2014 5,492 $ 681 $ – $ 2013 4,051 322 1,345 $ $ $ On April 1, 2014, the Company completed the acquisition of certain Canadian crude oil and natural gas properties in the North American Exploration and Production segment, including exploration and evaluation assets of $823 million, for cash consideration of $3,110 million, subject to final closing adjustments. The transaction was accounted for using the acquisition method of accounting. In connection with this acquisition, the Company assumed associated asset retirement obligations of $242 million and other long-term liabilities of $49 million. No debt obligations were assumed and no net deferred income tax liabilities were recognized. The above amounts are estimates and may be subject to change based on the receipt of new information. During 2014, the Company acquired a number of additional producing crude oil and natural gas properties in the North American Exploration and Production segment for net cash consideration of $643 million (2013 – $252 million; 2012 – $144 million). These transactions were accounted for using the acquisition method of accounting. In connection with these acquisitions, the Company acquired net working capital of $28 million, assumed associated asset retirement obligations of $162 million (2013 – $131 million; 2012 – $12 million) and recognized net deferred income tax assets of $91 million (2013 – $75 million; 2012 – $nil) related to temporary differences in the carrying amount of certain of the acquired properties and their tax bases. No debt obligations were assumed. The Company recognized after-tax gains of $137 million (2013 – $65 million; 2012 – $nil) on these acquisitions. The above amounts are estimates and may be subject to change based on the receipt of new information. The Company capitalizes construction period interest for qualifying assets based on costs incurred and the Company’s cost of borrowing. Interest capitalization to a qualifying asset ceases once the asset is substantially available for its intended use. During 2014, pre-tax interest of $204 million (2013 – $175 million; 2012 – $98 million) was capitalized to property, plant and equipment using a weighted average capitalization rate of 3.9% (2013 – 4.4%; 2012 – 4.8%). Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 73 73 15-03-12 6:20 PM 8. OTHER LONG-TERM ASSETS Investment in North West Redwater Partnership North West Redwater Partnership subordinated debt (1) Risk Management (note 17) Other Less: current portion (1) Includes accrued interest. 2014 2013 $ $ 298 $ 120 599 167 1,184 510 674 $ 306 – – 136 442 – 442 Other long-term assets include an investment in the 50% owned Redwater Partnership. Based on Redwater Partnership’s voting and decision-making structure and legal form, the investment is accounted for using the equity method. Redwater Partnership has entered into agreements to construct and operate a 50,000 barrel per day bitumen upgrader and refinery (the “Project”) under processing agreements that target to process 12,500 barrels per day of bitumen feedstock for the Company and 37,500 barrels per day of bitumen feedstock for the Alberta Petroleum Marketing Commission (“APMC”), an agent of the Government of Alberta, under a 30 year fee-for-service tolling agreement. During 2014, Redwater Partnership, the Company and APMC amended certain terms of the processing agreements. In conjunction with these amendments, in order to provide financing for Project completion based on the current revised Project cost estimate of approximately $8,500 million, the Company, along with APMC, each committed to provide additional funding up to $350 million by January 2016 in the form of subordinated debt bearing interest at prime plus 6%. During 2014, the Company and APMC each provided $113 million of subordinated debt. Subsequent to December 31, 2014, the Company and APMC each provided an additional $112 million of subordinated debt. Should final Project costs exceed the revised cost estimate, the Company and APMC have agreed, subject to the Company being able to meet certain funding conditions, to fund any shortfall in available third party commercial lending required to attain Project completion. During 2014, Redwater Partnership executed a $3,500 million syndicated credit facility with a group of financial institutions maturing June 2018 and repaid and cancelled its $1,200 million credit facility previously in place. As at December 31, 2014, Redwater Partnership had borrowings of $913 million under the syndicated credit facility. In addition, during 2014, Redwater Partnership issued $500 million of 3.20% series A senior secured bonds due July 2024 and $500 million of 4.05% series B senior secured bonds due July 2044. Subsequent to December 31, 2014, Redwater Partnership issued $500 million of 2.10% series C senior secured bonds due February 2022 and $500 million of 3.70% series D senior secured bonds due February 2043. Under its processing agreement, beginning on the earlier of the commercial operations date of the refinery and June 1, 2018, the Company is unconditionally obligated to pay its 25% pro rata share of the debt portion of the monthly cost of service toll, including interest, fees and principal repayments, of the syndicated credit facility and bonds, over the tolling period of 30 years. Redwater Partnership has entered into various agreements related to the engineering, procurement and construction of the Project. These contracts can be cancelled by Redwater Partnership upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. The assets, liabilities, partners’ equity and equity loss related to Redwater Partnership and the Company’s 50% interest at December 31, 2014 were comprised as follows: Current assets Non-current assets Current liabilities Non-current liabilities Partners’ equity Equity loss Redwater Partnership 100% interest Company 50% interest $ $ $ $ $ $ 132 $ 3,062 $ 454 $ 2,144 $ 596 $ 16 $ 66 1,531 227 1,072 298 8 74 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 74 15-03-12 6:20 PM 9. LONG-TERM DEBT Canadian dollar denominated debt, unsecured Bank credit facilities Medium-term notes 4.95% debentures due June 1, 2015 3.05% debentures due June 19, 2019 2.60% debentures due December 3, 2019 2.89% debentures due August 14, 2020 3.55% debentures due June 3, 2024 US dollar denominated debt, unsecured Commercial paper (US$500 million) US dollar debt securities 1.45% due November 14, 2014 (2014 – US$nil; 2013 – US$500 million) 4.90% due December 1, 2014 (2014 – US$nil; 2013 – US$350 million) Three-month LIBOR plus 0.375% due March 30, 2016 (2014 – US$500 million, 2013 – US$nil) 6.00% due August 15, 2016 (US$250 million) 5.70% due May 15, 2017 (US$1,100 million) 1.75% due January 15, 2018 (2014 – US$600 million; 2013 – US$nil) 5.90% due February 1, 2018 (US$400 million) 3.45% due November 15, 2021 (US$500 million) 3.80% due April 15, 2024 (US$500 million, 2013 – US$nil) 3.90% due February 1, 2025 (2014 – US$600 million; 2013 – US$nil) 7.20% due January 15, 2032 (US$400 million) 6.45% due June 30, 2033 (US$350 million) 5.85% due February 1, 2035 (US$350 million) 6.50% due February 15, 2037 (US$450 million) 6.25% due March 15, 2038 (US$1,100 million) 6.75% due February 1, 2039 (US$400 million) Less: original issue discount on US dollar debt securities (1) Fair value impact of interest rate swaps on US dollar debt securities (2) Long-term debt before transaction costs Less: transaction costs (1) (3) Less: current portion of commercial paper current portion of long-term debt (1) (2) (3) 2014 2013 $ 2,404 $ 1,246 400 500 500 500 500 400 500 – 500 – 4,804 2,646 580 – – 580 290 1,276 696 464 580 580 696 464 406 406 523 1,276 464 (21) 9,260 – 9,260 14,064 (62) 14,002 580 400 13,022 $ $ 532 532 372 – 266 1,169 – 426 532 – – 426 372 372 479 1,169 426 (18) 7,055 9 7,064 9,710 (49) 9,661 532 912 8,217 (1) The Company has included unamortized original issue discounts and directly attributable transaction costs in the carrying amount of the outstanding debt. (2) The carrying amount of US$350 million of 4.90% notes repaid December 2014 was adjusted by $9 million at December 31, 2013 to reflect the fair value impact of hedge accounting. (3) Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. BANK CREDIT FACILITIES AND COMMERCIAL PAPER As at December 31, 2014, the Company had in place bank credit facilities of $5,627 million available for general corporate purposes, comprised of: ■■ ■■ ■■ ■■ ■■ a $100 million demand credit facility; a $1,000 million non-revolving term credit facility maturing March 2016, subsequently extended to January 2017; a $1,500 million revolving syndicated credit facility maturing June 2016; a $3,000 million revolving syndicated credit facility maturing June 2017; and, a £15 million demand credit facility related to the Company’s North Sea operations. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 75 75 15-03-12 6:20 PM Each of the $1,500 million and $3,000 million facilities is extendible annually for one-year periods at the mutual agreement of the Company and the lenders. If the facilities are not extended, the full amount of the outstanding principal would be repayable on the maturity date. Borrowings under these facilities may be made by way of pricing referenced to Canadian dollar or US dollar bankers’ acceptances, or LIBOR, US base rate or Canadian prime loans. In connection with the agreement to acquire certain producing Canadian crude oil and natural gas properties (refer to note 7), the Company arranged a $1,000 million unsecured non-revolving bank credit facility. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar bankers’ acceptances or Canadian prime loans. As at December 31, 2014, the Company had $1,000 million outstanding under this facility. Subsequent to December 31, 2014 the existing $1,000 million non-revolving term credit facility was extended and now matures January 2017. In addition the Company entered into a new $1,500 million non-revolving three-year term credit facility maturing April 2018. Borrowings under this facility may be made by way of pricing referenced to Canadian dollar or US dollar bankers’ acceptances, or LIBOR, US base rate or Canadian prime loans. The Company’s borrowings under its US commercial paper program are authorized up to a maximum US$1,500 million. The Company reserves capacity under its bank credit facilities for amounts outstanding under this program. The Company’s weighted average interest rate on bank credit facilities and commercial paper outstanding as at December 31, 2014, was 2.2% (December 31, 2013 – 1.9%), and on long-term debt outstanding for the year ended December 31, 2014 was 3.9% (December 31, 2013 – 4.4%). At December 31, 2014 letters of credit and guarantees aggregating $359 million, including a $39 million financial guarantee related to Horizon and $214 million of letters of credit related to North Sea operations, were outstanding. The letters of credit are supported by dedicated credit facilities. MEDIUM-TERM NOTES During 2014, the Company issued $500 million of 2.60% medium-term notes due December 2019 and $500 million of 3.55% medium-term notes due June 2024. After issuing these securities, the Company has $2,000 million remaining on its outstanding $3,000 million base shelf prospectus that allows for the issue of medium-term notes in Canada, which expires in December 2015. If issued, these securities will bear interest as determined at the date of issuance. During 2013, the Company repaid $400 million of 4.50% medium-term notes and issued $500 million of 2.89% medium-term notes due August 2020 under a previous base shelf prospectus. US DOLLAR DEBT SECURITIES During 2014, the Company issued US$500 million of three-month LIBOR plus 0.375% notes due March 2016, and concurrently entered into cross currency swaps to fix the foreign currency exchange rate risk at three-month CDOR plus 0.309% and $555 million (note 17). In addition, the Company issued US$500 million of 3.80% notes due April 2024, US$600 million of 1.75% notes due January 2018, and US$600 million of 3.90% notes due February 2025. After issuing these securities, the Company has US$800 million remaining on its outstanding US$3,000 million base shelf prospectus that allows for the issue of US dollar debt securities in the United States, which expires in December 2015. If issued, these securities will bear interest as determined at the date of issuance. During 2014, the Company repaid US$500 million of 1.45% notes and US$350 million of 4.90% notes. (2013 – US$400 million of 5.15% notes). SCHEDULED DEBT REPAYMENTS Scheduled debt repayments are as follows: Year 2015 2016 2017 2018 2019 Thereafter Repayment 980 2,397 2,153 1,160 1,000 6,395 $ $ $ $ $ $ 76 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 76 15-03-12 6:20 PM 10. OTHER LONG-TERM LIABILITIES Asset retirement obligations Share-based compensation Risk management (note 17) Other Less: current portion 2014 $ 4,221 $ 203 – 70 4,494 319 $ 4,175 $ 2013 4,162 260 136 65 4,623 275 4,348 ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and have been discounted using a weighted average discount rate of 4.6% (2013 – 5.0%; 2012 – 4.3%). Reconciliations of the discounted asset retirement obligations were as follows: Balance – beginning of year Liabilities incurred Liabilities acquired Liabilities settled Asset retirement obligation accretion Revision of cost, inflation rates and timing estimates Change in discount rate Foreign exchange adjustments Balance – end of year Less: current portion SEGMENTED ASSET RETIREMENT OBLIGATIONS Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream 2014 2013 $ 4,162 $ 41 4,266 $ 62 404 (346) 193 (907) 558 116 4,221 121 131 (207) 171 375 (723) 87 4,162 – $ 4,100 $ 4,162 $ 2012 3,577 51 12 (204) 151 384 315 (20) 4,266 – 4,266 2014 2013 $ $ 2,012 $ 1,169 255 783 2 4,221 $ 1,707 1,090 225 1,138 2 4,162 SHARE-BASED COMPENSATION As the Company’s Option Plan provides current employees with the right to elect to receive common shares or a cash payment in exchange for stock options surrendered, a liability for potential cash settlements is recognized. The current portion represents the maximum amount of the liability payable within the next twelve month period if all vested stock options are surrendered for cash settlement. 2014 2013 Balance – beginning of year $ 260 $ Share-based compensation expense (recovery) Cash payment for stock options surrendered Transferred to common shares Capitalized to (recovered from) Oil Sands Mining and Upgrading Balance – end of year Less: current portion 66 (8) (129) 14 203 158 154 $ 135 (4) (50) 25 260 216 $ 45 $ 44 $ Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 77 2012 432 (214) (7) (45) (12) 154 129 25 77 15-03-12 6:20 PM The share-based compensation liability of $203 million at December 31, 2014 (2013 – $260 million; 2012 – $154 million) was estimated using the Black-Scholes valuation model with the following weighted average assumptions: Fair value Share price Expected volatility Expected dividend yield Risk free interest rate Expected forfeiture rate Expected stock option life (1) (1) At original time of grant. $ $ 2014 2013 5.51 $ 35.92 $ 25.1% 7.08 $ 35.94 $ 27.2% 2.5% 1.2% 4.7% 4.5 years 2.2% 1.5% 4.6% 4.5 years 2012 4.60 28.64 32.6% 1.5% 1.3% 4.2% 4.5 years The intrinsic value of vested stock options at December 31, 2014 was $40 million (2013 – $72 million; 2012 – $36 million). 11. INCOME TAXES The provision for income tax was as follows: 2014 2013 2012 Current corporate income tax – North America $ 702 $ 544 $ Current corporate income tax – North Sea Current corporate income tax – Offshore Africa (1) Current PRT (2) (recovery) expense – North Sea Other taxes Current income tax expense Deferred corporate income tax expense Deferred PRT (2) expense (recovery) – North Sea Deferred income tax expense (recovery) Income tax expense Includes current income taxes relating to disposition of properties in 2013. (1) (2) Petroleum Revenue Tax. (68) 43 (273) 23 427 681 126 807 1,234 $ $ 23 202 (56) 22 735 163 (132) 31 766 $ 366 115 206 44 16 747 – (30) (30) 717 The provision for income tax is different from the amount computed by applying the combined statutory Canadian federal and provincial income tax rates to earnings before taxes. The reasons for the difference are as follows: Canadian statutory income tax rate Income tax provision at statutory rate Effect on income taxes of: UK PRT and other taxes Impact of deductible UK PRT and other taxes on corporate income tax Foreign and domestic tax rate differentials Non-taxable portion of foreign exchange loss (gain) Stock options exercised for common shares Income tax rate and other legislative changes Non-taxable gain on corporate acquisitions Revisions arising from prior year tax filings Other 2014 25.1% 1,296 $ 2013 25.1% 762 $ 2012 25.1% 655 $ (124) (166) 85 (61) 36 14 – (34) 5 17 111 (66) 14 33 15 (16) 57 22 30 (13) 63 (2) (56) 58 – (10) (8) 717 Income tax expense $ 1,234 $ 766 $ 78 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 78 15-03-12 6:20 PM The following table summarizes the temporary differences that give rise to the net deferred income tax liability: Deferred income tax liabilities Property, plant and equipment and exploration and evaluation assets Timing of partnership items Unrealized risk management activities Unrealized foreign exchange gain on long-term debt Deferred PRT PRT deduction for corporate income tax Deferred income tax assets Asset retirement obligations Loss carryforwards Unrealized risk management activities Deferred PRT PRT deduction for corporate income tax Other 2014 2013 $ 9,985 $ 437 120 10 37 – 9,180 632 – 87 – 56 10,589 9,955 (1,362) (1,326) (117) – – (23) (117) (1,619) 8,970 $ Net deferred income tax liability $ Movements in deferred tax assets and liabilities recognized in net earnings during the year were as follows: 2014 2013 Property, plant and equipment and exploration and evaluation assets $ 647 $ 250 $ Timing of partnership items Unrealized foreign exchange gain on long-term debt Unrealized risk management activities Asset retirement obligations Loss carryforwards Deferred PRT PRT deduction for corporate income tax Other (195) (77) 142 119 109 126 (77) 13 $ 807 $ (199) (55) 13 76 25 (132) 78 (25) 31 $ The following table summarizes the movements of the net deferred income tax liability during the year: Balance – beginning of year Deferred income tax expense (recovery) Deferred income tax expense included in other comprehensive income Foreign exchange adjustments Business combinations Balance – end of year 2014 2013 $ $ 8,183 $ 807 1 70 (91) 8,970 $ 8,174 $ 31 – 53 (75) 8,183 $ (199) (23) (90) – (134) (1,772) 8,183 2012 465 (234) (7) – (238) – (30) 19 (5) (30) 2012 8,221 (30) 4 (21) – 8,174 Current income taxes recognized in each operating segment will vary depending upon available income tax deductions related to the nature, timing and amount of capital expenditures incurred in any particular year. During 2013, the Government of British Columbia substantively enacted legislation to increase its provincial corporate income tax rate effective April 1, 2013. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $15 million. During 2012, the UK government enacted legislation to restrict the combined corporate and supplementary income tax relief on UK North Sea decommissioning expenditures to 50%. As a result of the income tax rate change, the Company’s deferred income tax liability was increased by $58 million. The Company files income tax returns in the various jurisdictions in which it operates. These tax returns are subject to periodic examinations in the normal course by the applicable tax authorities. The tax returns as prepared may include filing positions that could be subject to differing interpretations of applicable tax laws and regulations, which may take several years to resolve. The Company does not believe the ultimate resolution of these matters will have a material impact upon the Company’s results of operations, financial position or liquidity. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 79 79 15-03-12 6:20 PM Deferred income tax assets are recognized for temporary differences to the extent that the realization of the related tax benefit through future taxable profits is probable. The Company has not recognized deferred income tax assets with respect to taxable capital loss carryforwards in excess of $1,000 million in North America, which can be carried forward indefinitely and only applied against future taxable capital gains. In addition, the Company has not recognized deferred income tax assets related to North American tax pools of approximately $700 million, which can only be claimed against income from certain oil and gas properties. Deferred income tax liabilities have not been recognized on the unremitted net earnings of wholly controlled subsidiaries. The Company is able to control the timing and amount of distributions and no taxes are payable on distributions from these subsidiaries provided that the distributions remain within certain limits. 12. SHARE CAPITAL AUTHORIZED Preferred shares issuable in a series. Unlimited number of common shares without par value. ISSUED Common shares Balance – beginning of year Issued upon exercise of stock options Previously recognized liability on stock options exercised for common shares Purchase of common shares under Normal Course Issuer Bid Balance – end of year 2014 2013 Number of shares (thousands) Amount Number of shares (thousands) Amount 1,087,322 $ 14,610 3,854 488 1,092,072 $ 5,415 3,709 130 – (10,095) 129 (39) – (10,165) 50 (35) 1,091,837 $ 4,432 1,087,322 $ 3,854 PREFERRED SHARES Preferred shares are issuable in a series. If issued, the number of shares in each series, and the designation, rights, privileges, restrictions and conditions attached to the shares will be determined by the Board of Directors of the Company. DIVIDEND POLICY The Company has paid regular quarterly dividends in January, April, July and October of each year since 2001. The dividend policy undergoes periodic review by the Board of Directors and is subject to change. On March 4 2015, the Board of Directors approved a quarterly dividend of $0.23 per common share, beginning with the dividend payable on April 1, 2015 ($0.225 per common share, approved on March 5, 2014 beginning with the dividend payable on April 1, 2014). In 2013, the Board of Directors approved a dividend of $0.20 per common share on November 5, 2013, beginning with the dividend payable on January 1, 2014 ($0.125 per common share, approved on March 6, 2013, beginning with the dividend payable on April 1, 2013). In 2012, the Board of Directors approved a quarterly dividend of $0.105 per common share, beginning with the dividend payable on April 1, 2012. NORMAL COURSE ISSUER BID In 2014, the Company announced a Normal Course Issuer Bid to purchase, through the facilities of the Toronto Stock Exchange and the New York Stock Exchange, during the twelve month period commencing April 2014 and ending April 2015, up to 54,596,899 common shares. The Company’s Normal Course Issuer Bid announced in 2013 expired April 2014. During 2014, the Company purchased for cancellation 10,095,000 common shares (2013 – 10,164,800 common shares; 2012 – 11,012,700 common shares) at a weighted average price of $44.85 per common share (2013 – $31.46 per common share; 2012 – $28.91 per common share), for a total cost of $453 million (2013 – $320 million; 2012 – $318 million). Retained earnings were reduced by $414 million (2013 – $285 million; 2012 – $281 million), representing the excess of the purchase price of common shares over their average carrying value. STOCK OPTIONS The Company’s Option Plan provides for the granting of stock options to employees. Stock options granted under the Option Plan have terms ranging from five to six years to expiry and vest over a five-year period. The exercise price of each stock option granted is determined at the closing market price of the common shares on the Toronto Stock Exchange on the day prior to the grant. Each stock option granted provides the holder the choice to purchase one common share of the Company at the stated exercise price or receive a cash payment equal to the difference between the stated exercise price and the market price of the Company’s common shares on the date of surrender of the stock option. The Option Plan is a “rolling 9%” plan, whereby the aggregate number of common shares that may be reserved for issuance under the plan shall not exceed 9% of the common shares outstanding from time to time. 80 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 80 15-03-12 6:20 PM The following table summarizes information relating to stock options outstanding at December 31, 2014 and 2013: Outstanding – beginning of year Granted Surrendered for cash settlement Exercised for common shares Forfeited Outstanding – end of year Exercisable – end of year 2014 2013 Stock options (thousands) Weighted average exercise price Stock options (thousands) Weighted average exercise price 72,741 $ 18,517 $ (1,047) $ (14,610) $ (3,893) $ 71,708 $ 23,717 $ 34.36 38.70 33.74 33.40 36.00 35.60 36.27 73,747 $ 17,823 $ (401) $ (5,415) $ (13,013) $ 72,741 $ 26,632 $ 34.13 32.51 23.83 24.03 34.93 34.36 35.27 The range of exercise prices of stock options outstanding and exercisable at December 31, 2014 was as follows: Range of exercise prices $23.87-$24.99 $25.00-$29.99 $30.00-$34.99 $35.00-$39.99 $40.00-$44.99 $45.00-$45.09 Stock options outstanding Stock options exercisable Stock options outstanding (thousands) Weighted average remaining term (years) Weighted average exercise price Stock options exercisable (thousands) Weighted average exercise price 50 11,493 21,378 24,136 12,939 1,712 71,708 0.21 $ 3.22 $ 3.20 $ 3.43 $ 2.80 $ 4.08 $ 3.23 $ 23.87 28.26 33.50 36.48 42.75 45.07 35.60 50 $ 3,584 $ 6,685 $ 7,166 $ 5,864 $ 368 $ 23,717 $ 13. ACCUMULATED OTHER COMPREHENSIVE INCOME The components of accumulated other comprehensive income, net of taxes, were as follows: Derivative financial instruments designated as cash flow hedges Foreign currency translation adjustment 14. CAPITAL DISCLOSURES 2014 94 $ (43) 51 $ $ $ 23.87 28.24 34.20 36.97 42.24 45.05 36.27 2013 81 (39) 42 The Company does not have any externally imposed regulatory capital requirements for managing capital. The Company has defined its capital to mean its long-term debt and consolidated shareholders’ equity, as determined at each reporting date. The Company’s objectives when managing its capital structure are to maintain financial flexibility and balance to enable the Company to access capital markets to sustain its on-going operations and to support its growth strategies. The Company primarily monitors capital on the basis of an internally derived financial measure referred to as its “debt to book capitalization ratio”, which is the arithmetic ratio of current and long-term debt divided by the sum of the carrying value of shareholders’ equity plus current and long-term debt. The Company’s internal targeted range for its debt to book capitalization ratio is 25% to 45%. This range may be exceeded in periods when a combination of capital projects, acquisitions, or lower commodity prices occurs. The Company may be below the low end of the targeted range when cash flow from operating activities is greater than current investment activities. At December 31, 2014, the ratio was within the target range at 33%. Readers are cautioned that the debt to book capitalization ratio is not defined by IFRS and this financial measure may not be comparable to similar measures presented by other companies. Further, there are no assurances that the Company will continue to use this measure to monitor capital or will not alter the method of calculation of this measure in the future. Long-term debt (1) Total shareholders’ equity Debt to book capitalization (1) Includes the current portion of long-term debt. $ $ 2014 14,002 $ 28,891 $ 33% 2013 9,661 25,772 27% Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 81 81 15-03-12 6:20 PM 15. NET EARNINGS PER COMMON SHARE Weighted average common shares outstanding – basic (thousands of shares) Effect of dilutive stock options (thousands of shares) Weighted average common shares outstanding – diluted (thousands of shares) Net earnings Net earnings per common share – basic – diluted 2014 2013 2012 1,091,754 1,088,682 1,097,084 5,068 1,859 2,435 1,096,822 1,090,541 1,099,519 $ $ $ 3,929 $ 2,270 $ 1,892 3.60 $ 3.58 $ 2.08 $ 2.08 $ 1.72 1.72 In 2014, the Company excluded 30,678,000 potentially anti-dilutive stock options from the calculation of diluted earnings per common share. 16. INTEREST AND OTHER FINANCING EXPENSE Interest and other financing expense: Long-term debt Other (1) Less: amounts capitalized on qualifying assets Total interest and other financing expense Total interest income Net interest and other financing expense 2014 2013 2012 $ $ 542 $ 457 $ (7) 535 204 331 (8) (2) 455 175 280 (1) 323 $ 279 $ 464 (1) 463 98 365 (1) 364 (1) Includes the fair value impact of interest rate swaps on US dollar debt securities. 17. FINANCIAL INSTRUMENTS The carrying amounts of the Company’s financial instruments by category were as follows: Asset (liability) Accounts receivable Other long-term assets Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) Asset (liability) Accounts receivable Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) 2014 Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost $ $ 1,889 $ 120 – – – – 2,009 $ – $ – $ 415 – – – – 415 $ 184 – – – – 184 $ 2013 – $ – (564) (3,279) (40) (14,002) (17,885) $ Financial assets at amortized cost Fair value through profit or loss Derivatives used for hedging Financial liabilities at amortized cost $ $ 1,427 $ – – – – 1,427 $ – $ – – (39) – (39) $ – $ – – (97) – (97) $ – $ (637) (2,519) (56) (9,661) (12,873) $ Total 1,889 719 (564) (3,279) (40) (14,002) (15,277) Total 1,427 (637) (2,519) (192) (9,661) (11,582) (1) Includes the current portion of long-term debt. 82 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 82 15-03-12 6:20 PM The carrying amounts of the Company’s financial instruments approximated their fair value, except for fixed rate long-term debt as noted below. The fair values of the Company’s recurring other long-term assets (liabilities) and fixed rate long-term debt are outlined below: Asset (liability) (1) (2) Other long-term assets (3) Fixed rate long-term debt (4) (5) Asset (liability) (1) (2) Other long-term liabilities Fixed rate long-term debt (4) (5) (6) 2014 Carrying amount Fair value Level 1 Level 2 Level 3 719 $ (11,018) (10,299) $ – $ (11,855) (11,855) $ 599 $ – 599 $ 120 – 120 2013 Carrying amount Fair value Level 1 Level 2 Level 3 (136) $ (7,883) (8,019) $ – $ (8,628) (8,628) $ (136) $ – (136) $ – – – $ $ $ $ (1) Excludes financial assets and liabilities where the carrying amount approximates fair value due to the liquid nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities). (2) There were no transfers between Level 1, 2 and 3 financial instruments. (3) The fair value of North West Redwater Partnership subordinated debt is based on the present value of future cash receipts. (4) The fair value of fixed rate long-term debt has been determined based on quoted market prices. (5) (6) The carrying amount of US$350 million of 4.90% notes repaid December 2014 was adjusted by $9 million at December 31, 2013 to reflect the fair value Includes the current portion of fixed rate long-term debt. impact of hedge accounting. The following provides a summary of the carrying amounts of derivative financial instruments held and a reconciliation to the Company’s consolidated balance sheets. Asset (liability) Derivatives held for trading Crude oil price collars Crude oil WCS (1) differential swaps Foreign currency forward contracts Natural gas AECO basis swaps Natural gas AECO put options, net of put premium financing obligations Cash flow hedges Foreign currency forward contracts Cross currency swaps Included within: Current portion of other long-term assets (liabilities) Other long-term assets (liabilities) (1) Western Canadian Select. 2014 2013 $ 410 $ (16) 21 – – 11 173 599 $ 436 $ 163 599 $ $ $ $ (33) – (3) (1) (2) (1) (96) (136) (38) (98) (136) During 2014, the Company recognized a loss of $3 million (2013 – gain of $4 million; 2012 – gain of $1 million) related to ineffectiveness arising from cash flow hedges. The estimated fair value of derivative financial instruments in Level 1 and Level 2 at each measurement date have been determined based on appropriate internal valuation methodologies and/or third party indications. Level 2 fair values determined using valuation models require the use of assumptions concerning the amount and timing of future cash flows and discount rates. In determining these assumptions, the Company primarily relied on external, readily-observable quoted market inputs including crude oil and natural gas forward benchmark commodity prices and volatility, Canadian and United States forward interest rate yield curves, and Canadian and United States foreign exchange rates, discounted to present value as appropriate. The resulting fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction and these differences may be material. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 83 83 15-03-12 6:20 PM RISK MANAGEMENT The Company uses derivative financial instruments to manage its commodity price, interest rate and foreign currency exposures. These financial instruments are entered into solely for hedging purposes and are not used for speculative purposes. The changes in estimated fair values of derivative financial instruments included in the risk management asset (liability) were recognized in the financial statements as follows: Asset (liability) Balance – beginning of year Cost of outstanding put options Net change in fair value of outstanding derivative financial instruments Risk management activities Foreign exchange Other comprehensive income Add: put premium financing obligations (1) Balance – end of year Less: current portion 2014 $ (136) $ – 451 270 14 599 – 599 436 $ 163 $ 2013 (257) 9 (39) 165 (5) (127) (9) (136) (38) (98) (1) The Company negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective options. These obligations are reflected in the 2013 risk management liability. Net (gains) losses from risk management activities for the years ended December 31 were as follows: Net realized risk management (gain) loss Net unrealized risk management (gain) loss $ $ 2014 (349) $ (451) (800) $ 2013 (116) $ 39 (77) $ 2012 162 (42) 120 FINANCIAL RISK FACTORS a) Market risk Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. The Company’s market risk is comprised of commodity price risk, interest rate risk, and foreign currency exchange risk. Commodity price risk management The Company periodically uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and natural gas production and with natural gas purchases. At December 31, 2014, the Company had the following derivative financial instruments outstanding to manage its commodity price risk: Sales contracts Crude oil Price collars WCS differential swaps Remaining term Volume Weighted average price Index Jan 2015 – Dec 2015 Jan 2015 – Mar 2015 50,000 bbl/d 30,000 bbl/d US$80.00 – US$120.52 US$21.49 Brent WCS The Company’s outstanding commodity derivative financial instruments are expected to be settled monthly based on the applicable index pricing for the respective contract month. Interest rate risk management The Company is exposed to interest rate price risk on its fixed rate long-term debt and to interest rate cash flow risk on its floating rate long-term debt. The Company periodically enters into interest rate swap contracts to manage its fixed to floating interest rate mix on long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2014, the Company had no interest rate swap contracts outstanding. 84 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 84 15-03-12 6:20 PM Foreign currency exchange rate risk management The Company is exposed to foreign currency exchange rate risk in Canada primarily related to its US dollar denominated long-term debt, commercial paper and working capital. The Company is also exposed to foreign currency exchange rate risk on transactions conducted in other currencies and in the carrying value of its foreign subsidiaries. The Company periodically enters into cross currency swap contracts and foreign currency forward contracts to manage known currency exposure on US dollar denominated long-term debt, commercial paper and working capital. The cross currency swap contracts require the periodic exchange of payments with the exchange at maturity of notional principal amounts on which the payments are based. At December 31, 2014, the Company had the following cross currency swap contracts outstanding: Remaining term Amount Exchange rate (US$/C$) Interest rate (US$) Interest rate (C$) Cross currency Swaps Jan 2015 – Mar 2016 US$500 1.109 Jan 2015 – Aug 2016 Jan 2015 – May 2017 Jan 2015 – Nov 2021 Jan 2015 – Mar 2038 US$250 US$1,100 US$500 US$550 1.116 1.170 1.022 1.170 Three-month LIBOR plus 0.375% 6.00% Three-month CDOR (1) plus 0.309% 5.40% 5.70% 3.45% 6.25% 5.10% 3.96% 5.76% (1) Canadian Dealer Offered Rate (“CDOR”). All cross currency swap derivative financial instruments were designated as hedges at December 31, 2014 and were classified as cash flow hedges. In addition to the cross currency swap contracts noted above, at December 31, 2014, the Company had US$1,766 million of foreign currency forward contracts outstanding, with terms of approximately 30 days or less, including US$500 million designated as cash flow hedges. Financial instrument sensitivities The following table summarizes the annualized sensitivities of the Company’s 2014 net earnings and other comprehensive income to changes in the fair value of financial instruments outstanding as at December 31, 2014, resulting from changes in the specified variable, with all other variables held constant. These sensitivities are prepared on a different basis than those sensitivities disclosed in the Company’s other continuous disclosure documents, are limited to the impact of changes in a specified variable applied to financial instruments only and do not represent the impact of a change in the variable on the operating results of the Company taken as a whole. Further, these sensitivities are theoretical, as changes in one variable may contribute to changes in another variable, which may magnify or counteract the sensitivities. In addition, changes in fair value generally cannot be extrapolated because the relationship of a change in an assumption to the change in fair value may not be linear. Increase (decrease) Commodity price risk Increase Brent US$1.00/bbl Decrease Brent US$1.00/bbl Increase WCS US$1.00/bbl Decrease WCS US$1.00/bbl Interest rate risk Increase interest rate 1% Decrease interest rate 1% Foreign currency exchange rate risk Increase exchange rate by US$0.01 Decrease exchange rate by US$0.01 Impact on other comprehensive income Impact on net earnings $ $ $ $ $ $ $ $ (13) $ 13 $ 2 $ (2) $ (14) $ 14 $ (48) $ 47 $ – – – – (2) (1) – – Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 85 85 15-03-12 6:20 PM b) Credit risk Credit risk is the risk that a party to a financial instrument will cause a financial loss to the Company by failing to discharge an obligation. Counterparty credit risk management The Company’s accounts receivable are mainly with customers in the crude oil and natural gas industry and are subject to normal industry credit risks. The Company manages these risks by reviewing its exposure to individual companies on a regular basis and where appropriate, ensures that parental guarantees or letters of credit are in place to minimize the impact in the event of default. At December 31, 2014, substantially all of the Company’s accounts receivable were due within normal trade terms. The Company is also exposed to possible losses in the event of nonperformance by counterparties to derivative financial instruments; however, the Company manages this credit risk by entering into agreements with counterparties that are substantially all investment grade financial institutions and other entities. At December 31, 2014, the Company had net risk management assets of $622 million with specific counterparties related to derivative financial instruments (December 31, 2013 – $nil). The carrying amount of financial assets approximates the maximum credit exposure. Liquidity risk c) Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. Management of liquidity risk requires the Company to maintain sufficient cash and cash equivalents, along with other sources of capital, consisting primarily of cash flow from operating activities, available credit facilities, commercial paper and access to debt capital markets, to meet obligations as they become due. The Company believes it has adequate bank credit facilities to provide liquidity to manage fluctuations in the timing of the receipt and/or disbursement of operating cash flows. The maturity dates for financial liabilities were as follows: Accounts payable Accrued liabilities Other long-term liabilities Long-term debt (1) Less than 1 year 1 to less than 2 years 2 to less than 5 years Thereafter $ $ $ $ 564 $ 3,279 $ 40 $ 980 $ – $ – $ – $ 2,397 $ – $ – $ – $ 4,313 $ – – – 6,395 (1) Long-term debt represents principal repayments only and does not reflect interest, original issue discounts or transaction costs. 18. COMMITMENTS AND CONTINGENCIES The Company has committed to certain payments as follows: Product transportation and pipeline Offshore equipment operating leases and offshore drilling Office leases Other $ $ $ $ 2015 2016 2017 2018 2019 Thereafter 442 $ 334 $ 301 $ 268 $ 237 $ 1,512 341 $ 42 $ 204 $ 92 $ 42 $ 125 $ 66 $ 44 $ 40 $ 59 $ 46 $ 1 $ 19 $ 47 $ – $ – 284 – In addition to the commitments disclosed above, the Company has entered into various agreements related to the engineering, procurement and construction of subsequent phases of Horizon.These contracts can be cancelled by the Company upon notice without penalty, subject to the costs incurred up to and in respect of the cancellation. The Company is defendant and plaintiff in a number of legal actions arising in the normal course of business. In addition, the Company is subject to certain contractor construction claims.The Company believes that any liabilities that might arise pertaining to any such matters would not have a material effect on its consolidated financial position. 86 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 86 15-03-12 6:20 PM 19. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Changes in non-cash working capital Accounts receivable Inventory Prepaids and other Accounts payable Accrued liabilities Current income tax assets (liabilities) Net changes in non-cash working capital Relating to: Operating activities Financing activities Investing activities Expenditures on exploration and evaluation assets Net proceeds on sale of exploration and evaluation assets Expenditures on property, plant and equipment Net proceeds on sale of property, plant and equipment Net expenditures on exploration and evaluation assets and property, plant and equipment 2014 2013 2012 (456) $ (243) $ (31) (30) (70) 741 (586) (76) (14) 175 127 94 (432) $ 63 $ (744) $ (22) 334 (432) $ 2014 1,190 $ – 10,252 (44) (33) $ (23) 119 63 $ 2013 119 $ (263) 7,249 (38) 869 (9) (8) (64) (138) (65) 585 447 (37) 175 585 2012 309 – 5,804 (9) 11,398 $ 7,067 $ 6,104 $ $ $ $ $ $ Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 87 87 15-03-12 6:20 PM 20. SEGMENTED INFORMATION The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. The bitumen in the segment is recovered through mining operations. Midstream activities include the Company’s pipeline operations, an electricity co-generation system and Redwater Partnership. Production activities that are not included in the above segments are reported in the segmented information as other. Inter-segment eliminations include internal transportation and electricity charges. Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream Inter–segment elimination and other 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2012 Total 2013 Segmented product sales $15,963 $ 12,659 $ 11,607 $ 701 $ 805 $ 928 $ 503 $ 824 $ 773 $ 4,095 $ 3,631 $ 2,871 $ 120 $ 110 $ 93 $ (81) $ (84) $ (77) $21,301 $ 17,945 $ 16,195 Less: royalties Segmented revenue Segmented expenses Production Transportation and blending Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk (2,159) (1,477) (1,268) 13,804 11,182 10,339 2,924 3,228 2,351 2,939 2,165 2,735 (2) 699 496 5 (2) 803 431 6 (2) 926 402 10 (43) 460 212 1 (137) 687 191 1 (199) 574 163 1 3,901 3,568 3,413 269 552 296 105 134 165 596 582 447 98 92 85 38 35 27 10 management activities (349) (116) 162 Gain on corporate acquisitions/ disposition of properties Equity loss from investment (137) – (65) – – – – – – – – – – – – – – – Total segmented expenses 9,665 8,769 8,560 808 1,024 735 328 10 – (224) – 112 7 – – – 336 $ 4,139 $ 2,413 $ 1,779 $ (109) $ (221) $ 191 $ 132 $ 575 $ 238 $ 1,534 $ 1,201 $ 690 $ 69 $ 64 $ 48 $ 6 $ 2 $ (8) 5,771 4,034 2,938 Segmented earnings (loss) before the following Non–segmented expenses Administration Share-based compensation Interest and other financing expense Unrealized risk management activities Foreign exchange loss (gain) Total non–segmented expenses Earnings before taxes Current income tax expense Deferred income tax expense (recovery) Net earnings 88 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 88 15-03-13 12:08 PM (234) (184) (137) 3,861 3,447 2,734 1,609 1,567 1,504 75 63 61 47 34 32 – – – – – – – – – – 120 34 – 9 – – – 8 – 110 34 – 8 – – – 4 – 93 29 – 7 – – – 9 – (81) (10) (77) – – – – – – (84) (15) (71) – – – – – – (2,438) (1,800) (1,606) (77) 18,863 16,145 14,589 (14) (55) 5,265 3,232 4,559 2,938 4,249 2,752 – – – – – 4,880 4,844 4,328 193 171 151 (349) (116) 162 (137) (289) 8 4 – 9 2,327 2,246 2,044 51 46 45 (87) (86) (69) 13,092 12,111 11,651 367 66 323 (451) 303 608 5,163 427 335 135 279 39 210 998 270 (214) 364 (42) (49) 329 3,036 735 2,609 747 807 31 (30) $ 3,929 $ 2,270 $ 1,892 20. SEGMENTED INFORMATION liquids and natural gas. The Company’s exploration and production activities are conducted in three geographic segments: North America, North Sea and Offshore Africa. These activities include the exploration, development, production and marketing of crude oil, natural gas The Company’s Oil Sands Mining and Upgrading activities are reported in a separate segment from exploration and production activities. The bitumen in the segment is recovered through mining operations. Midstream activities include the Company’s pipeline operations, an electricity co-generation system and Redwater Partnership. Production activities that are not included in the above segments are reported in the segmented information as other. Inter-segment eliminations include internal transportation and electricity charges. Exploration and Production Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenue and segment results include transactions between business segments.These transactions and any unrealized profits and losses are eliminated on consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers are based on the location of the seller. Operating segments are reported in a manner consistent with the internal reporting provided to the Company’s chief operating decision makers. North America North Sea Offshore Africa Oil Sands Mining and Upgrading Midstream Inter–segment elimination and other 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 Total 2013 2012 Segmented product sales $15,963 $ 12,659 $ 11,607 $ 701 $ 805 $ 928 $ 503 $ 824 $ 773 $ 4,095 $ 3,631 $ 2,871 $ 120 $ 110 $ 93 $ (81) $ (84) $ (77) $21,301 $ 17,945 $ 16,195 (2,159) (1,477) (1,268) 13,804 11,182 10,339 2,924 3,228 2,351 2,939 2,165 2,735 (2) 699 496 5 (2) 803 431 6 (2) 926 402 10 (43) 460 212 1 (234) (184) (137) 3,861 3,447 2,734 1,609 1,567 1,504 75 63 61 3,901 3,568 3,413 269 552 296 105 134 165 596 582 447 98 92 85 38 35 27 10 management activities (349) (116) 162 Gain on corporate acquisitions/ disposition of properties Equity loss from investment (137) – (65) – – – – – – – – – – – – – – – 47 34 32 – – – – – – – – – – 120 34 – 9 – – – 8 – 110 34 – 8 – – – 4 – 93 29 – 7 – – – 9 – (81) (10) (77) – – – – – – (84) (15) (71) – – – – – – (2,438) (1,800) (1,606) (77) 18,863 16,145 14,589 (14) (55) 5,265 3,232 4,559 2,938 4,249 2,752 – – – – – 4,880 4,844 4,328 193 171 151 (349) (116) 162 (137) (289) 8 4 – 9 Total segmented expenses 9,665 8,769 8,560 808 1,024 735 328 336 2,327 2,246 2,044 51 46 45 (87) (86) (69) 13,092 12,111 11,651 $ 4,139 $ 2,413 $ 1,779 $ (109) $ (221) $ 191 $ 132 $ 575 $ 238 $ 1,534 $ 1,201 $ 690 $ 69 $ 64 $ 48 $ 6 $ 2 $ (8) 5,771 4,034 2,938 (137) 687 191 1 10 – (224) – 112 (199) 574 163 1 7 – – – 367 66 323 (451) 303 608 5,163 427 335 135 279 39 210 998 270 (214) 364 (42) (49) 329 3,036 735 2,609 747 807 31 (30) $ 3,929 $ 2,270 $ 1,892 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 89 89 15-03-12 6:20 PM Less: royalties Segmented revenue Segmented expenses Production Transportation and blending Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk Segmented earnings (loss) before the following Non–segmented expenses Administration Share-based compensation Interest and other financing expense Unrealized risk management activities Foreign exchange loss (gain) Total non–segmented expenses Earnings before taxes Current income tax expense Deferred income tax expense (recovery) Net earnings CAPITAL EXPENDITURES (1) 2014 Non-cash and fair value changes (2) Net expenditures Capitalized costs Net expenditures 2013 Non-cash and fair value changes (2) Capitalized costs Exploration and evaluation assets Exploration and Production North America North Sea Offshore Africa (3) Property, plant and equipment Exploration and Production North America North Sea Offshore Africa Oil Sands Mining and Upgrading (4) Midstream Head office $ $ $ $ 1,103 $ – 87 1,190 $ (247) $ – – (247) $ 856 $ – 87 943 $ 90 $ – (10) 80 $ (84) $ – – (84) $ 6 – (10) (4) 6,397 $ 399 $ 6,796 $ 3,936 $ (450) $ 400 194 6,991 3,110 62 86 (1) 484 (528) – 486 193 7,475 2,582 62 334 114 4,384 2,592 197 (35) (17) (502) (189) (1) 45 10,208 $ (1) (45) $ 44 10,163 $ 38 7,211 $ – (692) $ 3,486 299 97 3,882 2,403 196 38 6,519 (1) This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. (2) Asset retirement obligations, deferred income tax adjustments related to differences between carrying amounts and tax values, transfers of exploration and evaluation assets, and other fair value adjustments. (3) The above noted figures in 2013 do not include the impact of a pre-tax gain on sale of exploration and evaluation assets totaling $224 million on the Company’s disposition of a 50% interest in its exploration right in South Africa. (4) Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. SEGMENTED ASSETS Exploration and Production North America North Sea Offshore Africa Other Oil Sands Mining and Upgrading Midstream Head office 2014 2013 $ $ 34,382 $ 2,711 1,214 18 20,702 1,048 125 60,200 $ 29,234 1,964 981 25 18,604 841 105 51,754 90 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 90 15-03-12 6:20 PM 21. REMUNERATION OF DIRECTORS AND SENIOR MANAGEMENT REMUNERATION OF NON-MANAGEMENT DIRECTORS Fees earned REMUNERATION OF SENIOR MANAGEMENT (1) Salary Common stock option based awards Annual incentive plans Long-term incentive plans Other compensation 2014 2013 3 $ 2 $ 2014 2013 3 $ 3 $ 8 4 17 – 32 $ 11 3 14 1 32 $ $ $ $ 2012 2 2012 2 12 3 9 – 26 (1) Senior management identified above are consistent with the disclosure on Named Executive Officers provided in the Company’s Information Circular to shareholders for the respective years. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 91 91 15-03-12 6:20 PM SUPPLEMENTARY OIL AND GAS INFORMATION (unaudited) This supplementary crude oil and natural gas information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil and Gas” and where applicable, financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”). For the years ended December 31, 2014, 2013, 2012 and 2011 the Company filed its reserves information under National Instrument 51-101 – “Standards of Disclosure of Oil and Gas Activities” (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards can be material. For the purposes of determining proved crude oil and natural gas reserves for SEC requirements as at December 31, 2014, 2013, 2012, and 2011 the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The Company has used the following 12-month average benchmark prices to determine its 2014 reserves for SEC requirements. Crude Oil and NGLs Natural Gas WTI Cushing Oklahoma (US$/bbl) 94.99 WCS (C$/bbl) 82.96 Canadian Light Sweet (C$/bbl) North Sea Brent (US$/bbl) Edmonton C5+ (C$/bbl) Henry Hub Louisiana (US$/MMBtu) AECO (C$/MMBtu) BC Westcoast Station 2 (C$/MMBtu) 94.84 101.80 104.52 4.30 4.60 4.45 A foreign exchange rate of US$1.00/C$1.099 was used in the 2014 evaluation, determined on the same basis as the 12-month average price. NET PROVED CRUDE OIL AND NATURAL GAS RESERVES The Company retains Independent Qualified Reserves Evaluators to evaluate the Company’s proved crude oil, bitumen, synthetic crude oil (“SCO”), natural gas and natural gas liquids (“NGLs”) reserves. ■■ For the years ended December 31, 2014, 2013, 2012, and 2011, the reports by GLJ Petroleum Consultants Ltd. covered 100% of the Company’s SCO reserves. With the inclusion of non-traditional resources within the definition of “oil and gas producing activities” in the SEC’s modernization of oil and gas reporting rules, effective January 1, 2010 these reserves volumes are included within the Company’s crude oil and natural gas reserves totals. ■■ For the years ended December 31, 2014, 2013, 2012, and 2011, the reports by Sproule Associates Limited and Sproule International Limited covered 100% of the Company’s crude oil, bitumen, natural gas and NGLs reserves. Proved crude oil and natural gas reserves, as defined within the SEC’s Regulation S-X, are the estimated quantities of oil and gas that by analysis of geoscience and engineering data demonstrate with reasonable certainty to be economically producible, from a given date forward, from known reservoirs under existing economic conditions, operating methods and government regulations. Developed crude oil and natural gas reserves are reserves of any category that can be expected to be recovered from existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of drilling a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped crude oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Estimates of crude oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing fields and technology becomes available and as future economic and operating conditions change. 92 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 92 15-03-12 6:20 PM The following tables summarize the Company’s proved and proved developed crude oil and natural gas reserves, net of royalties, as at December 31, 2014, 2013, 2012, and 2011: Crude Oil and NGLs (MMbbl) Oil Bitumen(1) Synthetic Crude Crude Oil & NGLs North America Total North Sea Offshore Africa North America Net Proved Reserves Reserves, December 31, 2011 1,836 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2012 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2013 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2014 Net proved developed reserves December 31, 2011 December 31, 2012 December 31, 2013 December 31, 2014 – – – – (30) 34 134 1,974 – – – – (35) (10) (4) 1,925 – – – – (38) (89) (18) 1,780 1,588 1,612 1,621 1,631 869 90 25 – – (70) 6 79 999 76 9 – – (71) (1) 56 1,068 112 10 – – (76) 11 23 1,148 269 348 431 401 366 3,071 244 5 9 2 – (31) (20) 39 370 13 7 8 – (33) 4 11 380 11 29 54 – (40) – 47 481 269 295 298 358 95 34 2 – (131) 20 252 3,343 89 16 8 – (139) (7) 63 3,373 123 39 54 – (154) (78) 52 3,409 2,126 2,255 2,350 2,390 – – – – (7) 4 (6) 235 – – 6 – (7) – (2) 232 – – – – (6) (9) (6) 211 78 66 59 39 88 – 1 – – (5) – 1 85 – – – – (5) (2) 2 80 – – – – (4) 1 – 77 61 55 30 21 Total 3,403 95 35 2 – (143) 24 247 3,663 89 16 14 – (151) (9) 63 3,685 123 39 54 – (164) (86) 46 3,697 2,265 2,376 2,439 2,450 (1) Bitumen as defined by the SEC, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all the Company’s thermal and primary heavy crude oil reserves have been classified as bitumen. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 93 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 93 15-03-13 11:58 AM Natural Gas (Bcf) Net Proved Reserves Reserves, December 31, 2011 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2012 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2013 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Economic revisions due to prices Revisions of prior estimates Reserves, December 31, 2014 Net proved developed reserves December 31, 2011 December 31, 2012 December 31, 2013 December 31, 2014 North America North Sea Offshore Africa 3,499 50 11 34 (1) (429) (596) 79 2,647 126 62 99 (1) (394) 489 206 3,234 119 443 1,229 – (514) 576 (70) 5,017 2,637 2,060 2,342 3,585 97 – – – – (1) 1 (14) 83 – – 14 – (1) – (4) 92 – – – – (2) (6) – 84 60 58 72 64 54 – – – – (6) – – 48 – – – – (8) (2) (1) 37 – – – – (6) 1 2 34 47 39 27 22 Total 3,650 50 11 34 (1) (436) (595) 65 2,778 126 62 113 (1) (403) 487 201 3,363 119 443 1,229 – (522) 571 (68) 5,135 2,744 2,157 2,441 3,671 94 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 94 15-03-12 6:20 PM CAPITALIZED COSTS RELATED TO CRUDE OIL AND NATURAL GAS ACTIVITIES (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation Net capitalized costs (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation Net capitalized costs (millions of Canadian dollars) Proved properties Unproved properties Less: accumulated depletion and depreciation Net capitalized costs 2014 North America North Sea Offshore Africa 82,554 $ 6,182 $ 3,858 $ 3,426 85,980 (33,750) – 6,182 (4,049) 131 3,989 (2,890) 52,230 $ 2,133 $ 1,099 $ 2013 North America North Sea Offshore Africa 73,176 $ 5,200 $ 3,356 $ 2,570 75,746 (29,729) – 5,200 (3,467) 39 3,395 (2,551) 46,017 $ 1,733 $ 844 $ North America 67,287 $ 2,564 69,851 (26,193) 43,658 $ 2012 North Sea 4,574 $ – 4,574 (2,709) 1,865 $ Offshore Africa 3,045 $ 47 3,092 (2,273) 819 $ $ $ $ $ $ $ Total 92,594 3,557 96,151 (40,689) 55,462 Total 81,732 2,609 84,341 (35,747) 48,594 Total 74,906 2,611 77,517 (31,175) 46,342 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 95 95 15-03-12 6:20 PM COSTS INCURRED IN CRUDE OIL AND NATURAL GAS ACTIVITIES (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Costs incurred 2014 North America North Sea Offshore Africa 3,323 $ 873 230 6,263 1 $ – – 485 – $ – 87 193 Total 3,324 873 317 6,941 10,689 $ 486 $ 280 $ 11,455 2013 North America North Sea Offshore Africa 250 $ 2 $ – $ 92 (2) 6,152 – – 297 4 25 97 6,492 $ 299 $ 126 $ 2012 North America North Sea Offshore Africa 144 $ 44 251 5,773 6,212 $ – $ – – 556 556 $ – $ 3 11 75 89 $ Total 252 96 23 6,546 6,917 Total 144 47 262 6,404 6,857 $ $ $ $ $ $ 96 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 96 15-03-12 6:20 PM RESULTS OF OPERATIONS FROM CRUDE OIL AND NATURAL GAS PRODUCING ACTIVITIES The Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012 are summarized in the following tables: (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Crude oil and natural gas revenue, net of royalties and blending costs Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax 2014 North America North Sea Offshore Africa $ 15,385 $ 696 $ 460 $ (4,533) (593) (4,497) (145) – (1,411) 4,206 $ $ (212) (1) (105) (10) – (29) 103 $ (496) (5) (269) (38) 147 (22) 13 $ 2013 North America North Sea Offshore Africa $ 12,274 $ 726 $ 687 $ $ $ (3,918) (483) (4,150) (126) – (903) 2,694 $ (191) (1) (134) (10) – (88) 263 $ (436) (6) (552) (35) 188 71 (44) $ 2012 North America North Sea Offshore Africa 10,609 $ (3,669) (479) (3,860) (117) – (623) 837 $ (402) (10) (296) (27) (14) (55) 574 $ (163) (1) (165) (7) – (55) Results of operations $ 1,861 $ 33 $ 183 $ Total 16,541 (5,241) (599) (4,871) (193) 147 (1,462) 4,322 Total 13,687 (4,545) (490) (4,836) (171) 188 (920) 2,913 Total 12,020 (4,234) (490) (4,321) (151) (14) (733) 2,077 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 97 97 15-03-12 6:20 PM STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED CRUDE OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN The following standardized measure of discounted future net cash flows from proved crude oil and natural gas reserves has been computed using the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day- of-the- month price for each month within the 12-month period prior to the end of the reporting period, costs as at the balance sheet date and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash flows. The Company does not believe that the standardized measure of discounted future net cash flows will be representative of actual future net cash flows and should not be considered to represent the fair value of the crude oil and natural gas properties. Actual net cash flows will differ from the presented estimated future net cash flows due to several factors including: ■■ Future production will include production not only from proved properties, but may also include production from probable and possible reserves; ■■ Future production of crude oil and natural gas from proved properties will differ from reserves estimated; ■■ Future production rates will vary from those estimated; ■■ Future prices and costs rather than 12-month average prices and costs as at the balance sheet date will apply; ■■ Economic factors such as interest rates, income tax rates, regulatory and fiscal environments and operating conditions will change; ■■ Future estimated income taxes do not take into account the effects of future exploration and evaluation expenditures; and ■■ Future development and asset retirement obligations will differ from those estimated. Future net revenues, development, production and asset retirement obligation costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash flows relating to proved crude oil and natural gas reserves based on the standardized measure as prescribed in FASB Topic 932 – “Extractive Activities – Oil and Gas”: (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows Standardized measure of future net cash flows $ (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows Standardized measure of future net cash flows $ 2014 North America North Sea Offshore Africa $ 322,100 $ (123,055) 24,786 $ (9,708) (56,651) (24,578) 117,816 (67,899) 49,917 $ (8,515) (4,816) 1,747 (813) 934 $ 2013 North America North Sea Offshore Africa $ 290,892 $ (116,984) 26,378 $ (9,921) (51,749) (20,384) 101,775 (65,063) 36,712 $ (7,602) (6,586) 2,269 (976) 1,293 $ 8,853 $ (2,171) (1,863) (1,178) 3,641 (1,672) 1,969 $ 9,146 $ (2,560) (1,840) (1,154) 3,592 (1,755) 1,837 $ Total 355,739 (134,934) (67,029) (30,572) 123,204 (70,384) 52,820 Total 326,416 (129,465) (61,191) (28,124) 107,636 (67,794) 39,842 98 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 98 15-03-12 6:20 PM (millions of Canadian dollars) Future cash inflows Future production costs Future development costs and asset retirement obligations Future income taxes Future net cash flows 10% annual discount for timing of future cash flows 2012 North America North Sea Offshore Africa $ 273,167 $ 26,922 $ (114,825) (9,369) 7,985 $ (2,428) (49,226) (16,688) 92,428 (61,878) (7,032) (7,662) 2,859 (1,330) (1,640) (949) 2,968 (1,313) Standardized measure of future net cash flows $ 30,550 $ 1,529 $ 1,655 $ Total 308,074 (126,622) (57,898) (25,299) 98,255 (64,521) 33,734 The principal sources of change in the standardized measure of discounted future net cash flows are summarized in the following table: (millions of Canadian dollars) 2014 2013 2012 Sales of crude oil and natural gas produced, net of production costs Net changes in sales prices and production costs Extensions, discoveries and improved recovery Changes in estimated future development costs Purchases of proved reserves in place Sales of proved reserves in place Revisions of previous reserve estimates Accretion of discount Changes in production timing and other Net change in income taxes Net change Balance – beginning of year Balance – end of year $ (10,321) $ 8,575 4,428 (2,821) 4,425 – (1,306) 5,154 5,895 (1,051) 12,978 39,842 52,820 $ $ (8,525) $ 6,992 2,304 (1,536) 638 (1) 622 4,388 2,341 (1,115) 6,108 33,734 39,842 $ (7,895) (7,994) 1,834 (3,492) 83 (1) 4,266 5,110 946 2,154 (4,989) 38,723 33,734 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:48 25079_CNR_2014_AR_BOOK.indb 99 99 15-03-12 6:20 PM TEN-YEAR REVIEW 2014 Years ended December 31 2013 FINANCIAL INFORMATION (1) (Cdn $ millions, except per share amounts) Net earnings 2,270 2.08 2.08 7,477 6.87 6.86 Per share - basic ($/share) Per share - diluted ($/share) Cash flow from operations (2) Per share - basic ($/share) Per share - diluted ($/share) 3,929 3.60 3.58 9,587 8.78 8.74 2012 2011 2010 (6) 2009 (7) 2008 (7) 2007 (7) 2006 (7) 2005 (7) 1,892 1.72 1.72 6,013 5.48 5.47 2,643 2.41 2.40 6,547 5.98 5.94 1,673 1.54 1.53 6,333 5.82 5.78 1,580 1.46 1.46 6,090 5.62 5.62 4,985 4.61 4.61 6,969 6.45 6.45 2,608 2.42 2.42 6,198 5.75 5.75 2,524 2.35 2.35 4,932 4.59 4.59 1,050 0.98 0.98 5,021 4.68 4.67 Capital expenditures, net of dispositions (including business combinations) Balance sheet information Working capital surplus (deficiency) Exploration and evaluation assets Property, plant and equipment, net Total assets Long-term debt Shareholders’ equity SHARE INFORMATION (1) Common shares outstanding (thousands) Weighted average shares outstanding - basic (thousands) Weighted average shares outstanding - diluted (thousands) Dividends declared ($/share) (8) Trading statistics (1) TSX – C$ Trading volume (thousands) Share Price ($/share) High Low Close NYSE – US$ Trading volume (thousands) Share Price ($/share) High Low Close RATIOS Debt to book capitalization (3) Return on average common shareholders’ equity, after tax (3) Daily production before royalties per ten thousand common shares (BOE/d) (1) Total proved plus probable reserves per common share (BOE) (1)(4) Net asset value ($/share) (1)(5) 11,744 7,274 6,308 6,414 5,514 2,997 7,451 6,425 12,025 4,932 (673) 3,557 52,480 60,200 14,002 28,891 (1,574) 2,609 46,487 51,754 9,661 25,772 (1,264) 2,611 44,028 48,980 8,736 24,283 (894) 2,475 41,631 47,278 8,571 22,898 (1,200) 2,402 38,429 42,954 8,485 20,368 (514) - 39,115 41,024 9,658 19,426 (28) - 38,966 42,650 12,596 18,374 (1,382) - 33,902 36,114 10,940 13,321 (832) - 30,767 33,160 11,043 10,690 (1,774) - 19,694 21,852 3,321 8,237 1,091,837 1,087,322 1,092,072 1,096,460 1,090,848 1,084,654 1,081,982 1,079,458 1,075,806 1,072,696 1,091,754 1,088,682 1,097,084 1,095,582 1,088,096 1,083,850 1,081,294 1,078,672 1,074,678 1,073,300 1,096,822 1,090,541 1,099,519 1,102,582 1,095,648 1,083,850 1,081,294 1,078,672 1,074,678 1,076,850 0.12 0.575 0.90 0.30 0.20 0.36 0.21 0.42 0.17 0.15 717,580 683,003 729,700 800,044 661,832 1,040,320 1,359,476 858,068 1,017,870 1,275,984 49.57 31.00 35.92 36.04 28.44 35.94 41.12 25.58 28.64 50.50 27.25 38.15 45.00 31.97 44.35 39.50 17.93 38.00 55.65 17.10 24.38 40.01 26.23 36.29 36.96 22.75 31.08 31.00 12.14 28.82 812,521 645,403 844,647 937,481 759,327 1,514,614 1,934,456 972,532 803,818 503,108 46.65 26.53 30.88 33.92 26.98 33.84 41.38 25.01 28.87 52.04 25.69 37.37 44.77 30.00 44.42 38.26 13.85 35.98 54.66 13.22 19.99 43.59 22.28 36.57 32.19 20.15 26.62 27.03 9.87 24.81 33% 27% 26% 27% 29% 33% 41% 45% 51% 29% 14% 7.2 8.1 78.99 9% 6.2 8% 6.0 12% 5.5 8% 5.8 8% 5.3 33% 22% 27% 14% 5.2 5.7 5.4 5.2 7.3 72.41 7.2 62.38 6.9 70.37 6.3 64.58 5.8 64.92 3.1 39.89 3.2 34.47 3.2 28.21 2.4 30.22 (1) Restated to reflect two-for-one share splits in May 2004, May 2005 and May 2010. (2) Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. Cash flow from operations may not be comparable to similar measures used by other companies. (3) Refer to the “Liquidity and Capital Resources” section of the MD&A for the definitions of these items. (4) Based upon company gross reserves (forecast price and costs, before royalties), using year-end common shares outstanding. Excludes Horizon SCO reserves prior to 2009. Prior to 2010, Company gross reserves were prepared using constant prices and costs. (5) Calculated as the net present value of future net revenue, before income tax, of the Company’s total proved plus probable reserves prepared using forecast prices and costs discounted at 10%, as reported in the Company’s AIF, with $300/acre added for core unproved property ($250/acre for core undeveloped land from 2005 to 2009, $75/acre for core undeveloped land for all years prior to 2005), less net debt and using year end common shares outstanding. Net debt is the Company’s long-term debt plus/minus the working capital deficit/surplus. Excludes Horizon SCO reserves prior to 2009. Future development costs and associated material well abandonment costs have been applied against the future net revenue. 2010 comparative figures have been restated in accordance with IFRS issued at December 31, 2011. (6) (7) Comparative figures for years prior to 2010 are in accordance with Canadian GAAP as previously reported and may not be prepared on a basis consistent with IFRS as adopted. (8) On March 5, 2014, the Board of Directors approved a quarterly dividend of $0.225 per common share, beginning with the dividend payable on April 1, 2014 ($0.20 per common share, approved on November 5, 2013, beginning with the dividend payable on January 1, 2014). 100 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:49 25079_CNR_2014_AR_BOOK.indb 100 15-03-12 6:20 PM Years ended December 31 OPERATING INFORMATION Crude oil and NGLs (MMbbl) (9) Company net proved reserves (after royalties) 2014 2013 2012 2011 2010 (6) 2009 2008 2007 2006 2005 North America North Sea Offshore Africa Horizon SCO (9) 3,380 204 78 3,662 - Company net proved and probable reserves (after royalties) North America North Sea Offshore Africa Horizon SCO (9) Natural gas (Bcf) (9) Company net proved reserves (after royalties) North America North Sea Offshore Africa 5,609 308 119 6,036 - 5,054 83 36 5,173 Company net proved plus probable reserves (after royalties) 6,791 114 68 6,973 3,290 224 80 3,594 - 5,135 325 122 5,582 - 3,684 91 38 3,813 5,138 125 70 5,333 3,268 227 85 3,580 - 5,119 332 127 5,578 - 3,540 82 48 3,670 4,907 102 76 5,085 3,007 228 87 3,322 - 4,777 349 131 5,257 - 3,778 98 54 3,930 5,125 134 83 5,342 2,763 252 101 3,116 - 4,293 376 149 4,818 - 3,638 78 76 3,792 4,870 107 113 5,090 2,664 240 123 3,027 - 4,172 387 179 4,738 - 3,027 67 85 3,179 3,992 94 124 4,210 948 256 142 1,346 1,946 1,599 399 191 2,189 2,944 3,523 67 94 3,684 4,619 94 131 4,844 920 310 128 1,358 1,761 1,545 405 186 2,136 2,680 3,521 81 64 3,666 4,602 113 88 4,803 887 299 130 1,316 1,596 1,502 422 195 2,119 2,542 3,705 37 56 3,798 4,857 93 99 5,049 694 290 134 1,118 1,626 1,035 417 206 1,658 2,566 2,741 29 72 2,842 3,548 69 110 3,727 North America North Sea Offshore Africa Total proved reserves (after royalties) (MMBOE) Total proved plus probable reserves (after royalties) (MMBOE) Daily production (before royalties) Crude oil and NGLs (Mbbl/d) North America - Exploration and Production North America - Oil Sands Mining and Upgrading North Sea Offshore Africa Natural gas (MMcf/d) North America North Sea Offshore Africa Total production (before royalties) (MBOE/d) Product pricing Average crude oil and NGLs price ($/bbl) (10) Average natural gas price ($/Mcf) (10) Average SCO price ($/bbl) (10) 4,524 4,230 4,191 3,977 3,748 3,557 1,960 1,969 1,949 1,592 7,198 6,471 6,426 6,147 5,666 5,440 2,996 2,937 2,961 2,279 391 111 17 12 531 1,527 7 21 1,555 790 77.04 4.83 100.27 344 100 18 16 478 1,130 4 24 1,158 671 73.81 3.58 100.75 326 86 20 19 451 1,198 2 20 1,220 655 72.44 2.70 90.74 296 40 30 23 389 1,231 7 19 1,257 599 79.16 3.99 101.48 271 91 33 30 425 1,217 10 16 1,243 632 65.81 4.08 77.89 234 50 38 33 355 1,287 10 18 1,315 575 57.68 4.53 70.83 244 - 45 27 316 1,472 10 13 1,495 565 82.41 8.39 - 247 - 56 28 331 1,643 13 12 1,668 609 55.45 6.85 - 235 - 60 37 332 1,468 15 9 1,492 581 53.65 6.72 - 222 - 68 23 313 1,416 19 4 1,439 553 46.86 8.57 - (9) For the years 2014 to 2010, company net reserves were prepared using forecast prices and costs; prior to 2010, company net reserves were prepared using constant prices and costs. Prior to December 31, 2009, the Company’s Horizon SCO reserves were reported separately in accordance with the SEC’s Industry Guide 7. With the SEC’s Final Rule in effect January 1, 2010, this SCO is now included in the Company’s crude oil and natural gas reserves totals. (10) For the years 2011 to 2014, product prices reflect realized product prices before transportation costs. Prior to 2011, product prices were reported net of transportation costs. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 101 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:49 25079_CNR_2014_AR_BOOK.indb 101 15-03-13 11:36 AM CORPORATE INFORMATION BOARD OF DIRECTORS *Catherine M. Best, FCA, ICD.D (1)(2) Corporate Director Calgary, Alberta N. Murray Edwards, O.C. (5) President, Edco Financial Holdings Ltd. Calgary/Banff, Alberta *Timothy W. Faithfull (1)(3) Corporate Director London, England *Honourable Gary A. Filmon, P.C., O.C., O.M. (1)(4) Corporate Director Winnipeg, Manitoba *Christopher L. Fong (3)(5) Corporate Director Calgary, Alberta *Ambassador Gordon D. Giffin (1)(4) Senior Partner, McKenna Long & Aldridge LLP Atlanta, Georgia *Wilfred A. Gobert (2)(4)(5) Corporate Director Calgary, Alberta Steve W. Laut (3) President, Canadian Natural Resources Limited Calgary, Alberta Keith A. J. MacPhail (3)(5) Executive Chairman Bonavista Energy Corporation Calgary, Alberta *Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C. (2)(4) Deputy Chair, TD Bank Group Cap Pelé, New Brunswick *Dr. Eldon R. Smith, OC., M.D. (2)(3) President, Eldon R. Smith & Associates Ltd. Emeritus Professor of Medicine and Former Dean, Faculty of Medicine, University of Calgary Calgary, Alberta *David A.Tuer (1)(5) Vice-Chairman and Chief Executive Officer, Teine Energy Ltd. Calgary, Alberta *Annette M. Verschuren, O.C. Chairman and Chief Executive Officer, NRSTOR Inc. Toronto, Ontario OFFICERS N. Murray Edwards Chairman of the Board Steve W. Laut President Tim S. McKay Chief Operating Officer Douglas A. Proll Executive Vice-President Lyle G. Stevens Executive Vice-President, Canadian Conventional Corey B. Bieber Chief Financial Officer and Senior Vice-President, Finance Réal M. Cusson Senior Vice-President, Marketing Réal J.H. Doucet Senior Vice-President, Horizon Projects Darren M. Fichter Senior Vice-President, Exploitation Peter J. Janson Senior Vice-President, Horizon Operations Terry J. Jocksch Senior Vice-President, Thermal Ronald K. Laing Senior Vice-President, Corporate Development and Land Paul M. Mendes Vice-President, Legal and General Counsel Bill R. Peterson SeniorVice-President, Production and Development Operations Ken W. Stagg Senior Vice-President, Exploration Scott G. Stauth Senior Vice-President, North American Operations Bruce E. McGrath Corporate Secretary (1) Audit Committee member (2) Compensation Committee member (3) Health, Safety & Environmental Committee member (4) Nominating, Governance & Risk Committee member (5) Reserves Committee member * Determined to be independent by the Nominating and Corporate Governance Committee and the Board of Directors and pursuant to the independent standards established under National Instrument 58-101 and the New York Stock Exchange Corporate Governance Listing Standards. 102 Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:49 25079_CNR_2014_AR_BOOK.indb 102 15-03-17 10:39 AM CORPORATE OFFICES HEAD OFFICE Canadian Natural Resources Limited 2100, 855 - 2 Street S.W. Calgary, AB T2P 4J8 Telephone: (403) 517-6700 Facsimile: (403) 517-7350 Website: www.cnrl.com INVESTOR RELATIONS Telephone: (403) 514-7777 Email: ir@cnrl.com INTERNATIONAL OFFICE CNR International (U.K.) Limited St. Magnus House, Guild Street Aberdeen AB11 6NJ Scotland REGISTRAR AND TRANSFER AGENT Computershare Trust Company of Canada Calgary, Alberta Toronto, Ontario Computershare Investor Services LLC New York, New York AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta INDEPENDENT QUALIFIED RESERVES EVALUATORS GLJ Petroleum Consultants Ltd. Calgary, Alberta Sproule Associates Limited Calgary, Alberta Sproule International Limited Calgary, Alberta STOCK LISTING - CNQ Toronto Stock Exchange The New York Stock Exchange COMPANY DEFINITION Throughout the annual report, Canadian Natural Resources Limited is referred to as “us”, “we”, “our”, “Canadian Natural”, or the “Company”. CURRENCY All amounts are reported in Canadian currency unless otherwise stated. ABBREVIATIONS Abbreviations can be found on page 22. METRIC CONVERSION CHART To convert Multiply by To barrels thousand cubic feet cubic metres cubic metres feet miles acres tonnes metres kilometres hectares tons 0.159 28.174 0.305 1.609 0.405 1.102 COMMON SHARE DIVIDEND The Company paid its first dividend on its common shares on April 1, 2001. Since then, dividends have been paid on the first day of every January, April, July and October. The following table shows the aggregate amount of the cash dividends declared per common share of the Company in each of its last three years ended December 31. Cash dividends declared per common share 2014 2013 2012 $ 0.90 $ 0.575 $ 0.42 NOTICE OF ANNUAL MEETING Canadian Natural’s Annual General Meeting of the Shareholders will be held on Thursday, May 7, 2015 at 1:00 p.m. Mountain Daylight Time in the Ballroom of the Metropolitan Centre, Calgary, Alberta. CORPORATE GOVERNANCE Canadian Natural, as a “foreign private issuer” listed on the New York Stock Exchange (“NYSE”), is not required to comply with most of the NYSE’s corporate governance standards and instead may rely on Canadian corporate governance practices. Canadian Natural’s corporate governance practices and disclosure of those practices are in compliance with National Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices. Under NYSE rules, Canadian Natural must disclose any significant differences between its corporate governance practices and those required to be followed by U.S. domestic companies under the NYSE’s corporate governance standards. Except as described below, Canadian Natural is in compliance with the NYSE’s corporate governance standards in all significant respects. Canadian Natural follows Toronto Stock Exchange (“TSX”) rules with respect to shareholder approval of equity compensation plans and material revisions to such plans. TSX rules provide that only the creation of or material amendments to equity compensation plans which provide for new issuance of securities are subject to shareholder approval. However, the NYSE requires shareholder approval of all equity compensation plans whether they provide for the delivery of newly issued securities, or rely on securities acquired in the open market by the issuing company for the purposes of redistribution to plan beneficiaries, and material revisions to such plans. Canadian Natural has a performance share unit plan pursuant to which common shares are purchased through the TSX. This is not a new issue of securities under the performance share unit plan and under TSX rules the plan is not subject to shareholder approval. Printed in Canada by McAra Printing. Design and produced by nonfiction studios inc. Canadian Natural 2014 Annual Report Premium Value. Defined Growth. Independent. 25079_CNR_2014_AR_004_108 | Black | 24-MAR-1512:14:49 25079_CNR_2014_AR_BOOK.indb 103 103 15-03-12 6:20 PM Canadian Natural Resources Limited 2100, 855 – 2 Street SW Calgary,AB T2P 4J8 www.cnrl.com T 403.517.6700 F 403.517.7350 E ir@cnrl.com 25079_CNR_2014_AR_004_108 | Black 285 | 24-MAR-1512:14:49 25079_CNR_2014_AR_BOOK.indb 104 15-03-12 6:20 PM