Canadian Natural Resources Annual Report 2005

Plain-text annual report

The Premium Value, Deﬁ ned Growth, Independent. 2005 Annual Report General information 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. Alberta natural gas reference location Annual Information Form barrel barrels per day billion cubic feet billion cubic feet per day barrels of oil equivalent barrels of oil equivalent per day Canadian dollars Coal Bed Methane Canadian Natural Upgrader Cyclic Steam Stimulation Enhanced Oil Recovery Exploration and Production Floating Production, Storage and Offtake Vessel Greenhouse Gas ABBREVIATIONS AECO AIF bbl bbl/d bcf bcf/d boe boe/d C$ CBM CNUG CSS EOR E&P FPSO GHG Horizon Project Horizon Oil Sands Project mbbl mbbl/d mboe mboe/d mcf mcf/d mmbbl mmboe mmbtu mmcf/d NGLs NYMEX NYSE OOIP SAGD SCO SEC tcf TSX UK US US$ WCS WCSB WTI thousand barrels thousand barrels per day thousand barrels of oil equivalent thousand barrels of oil equivalent per day thousand cubic feet thousand cubic feet per day million barrels million barrels of oil equivalent million British thermal units million cubic feet per day Natural gas liquids New York Mercantile Exchange New York Stock Exchange Original Oil In Place Steam Assisted Gravity Drainage Synthetic light crude oil Securities and Exchange Commission trillion cubic feet Toronto Stock Exchange United Kingdom United States United States dollars Western Canadian Select crude oil blend Western Canadian Sedimentary Basin West Texas Intermediate CAUTIONARY STATEMENTS Certain information regarding the Company contained herein may constitute forward-looking statements under applicable securities laws. Such statements are subject to known or unknown risks and uncertainties that may cause actual results to differ materially from those anticipated or implied in the forward- looking statements. Please refer to page 45 for the complete special note regarding forward-looking statements. All production and sales statistics represent Canadian Natural’s working interest amounts before deduction of royalties unless stated otherwise. Where volumes are reported in barrels of oil equivalent (“boe”), natural gas is converted to oil at six thousand cubic feet per barrel. This conversion may be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Methodologies for determining annual reserves are described on pages 40 to 44. This report also includes references to ﬁ nancial measures commonly used in the oil and gas industry that are not deﬁ ned by Generally Accepted Accounting Principles (“GAAP”). The Company uses these measures to evaluate its performance, however they should not be considered an alternative to or more meaningful than net earnings. COMMON SHARE DIVIDEND The Company paid its ﬁ rst dividend on its common shares on April 1st, 2001. Since then, dividends have been paid on the ﬁ rst day of every January, April, July and October. The following table, restated for the two-for-one subdivisions of the common shares that occurred in May 2004 and May 2005, shows the aggregate amount of the cash dividends declared per common share in each of its last three years ended December 31. Cash dividends declared per common share 2005 2004 2003 $ 0.24 $ 0.20 $ 0.15 NOTICE OF ANNUAL MEETING Canadian Natural’s Annual General Meeting of Shareholders will be held on Thursday, May 4, 2006 at 3:00 p.m. Mountain Daylight Time in the Ballroom of the Metropolitan Centre, Calgary, Alberta. METRIC CONVERSION CHART To convert barrels thousand cubic feet feet miles acres tonnes To cubic metres cubic metres metres kilometres hectares tons Multiply by 0.159 28.174 0.305 1.609 0.405 1.102 The People Our people are motivated and competent. Our technical skills are compounding, allowing us to maintain our core competencies and pursue larger and more complex projects. The Plan Our exploitation based strategy allocates capital in a balanced manner, providing near-, mid- and long-term growth initiatives. This plan provides signiﬁ cant transparency to investors. The Assets Our strong asset base is comprised of a deep portfolio of conventional oil and gas opportunities in North America, the North Sea and Offshore West Africa. This is bolstered by a vast oil sands resource base in Alberta capable of supporting over 675,000 barrels per day of light sweet SCO production for years to come. Capitalizing on opportunities. Relying on our People and applying their expanding technical skills to our vast Asset portfolio has allowed us to extend our Plan for oil sands development. This includes targeting further expansions at the Horizon Project as well as the development of our in-situ lands together with the construction of the Canadian Natural Upgrader which will be capable of upgrading this product to light, sweet Synthetic Crude Oil. TABLE OF CONTENTS Financial Highlights Letter to Shareholders 4 7 12 The People 14 The Plan: Review of Operations 18 The Plan: Marketing 22 The Plan: Financial Plan Conventional Operations Year in Review COST CONTROL remains strong, reﬂ ecting the beneﬁ ts of leveraging a large infrastructure to create economies of scale. This ability also lends itself to capital efﬁ ciencies. NET CONVENTIONAL PROVED RESERVES additions were 145% of net production at a ﬁ nding and onstream cost of $13.41/boe (3-year average $12.55/boe). Using net proved and probable reserves we replaced 195% of net production at a ﬁ nding and onstream cost of $9.97/boe (3-year average $8.05/boe). In addition, we booked 2.2 billion barrels of gross proved (3.4 billion barrels of gross proved and probable) mineable bitumen reserves at our Horizon Project. CANADIAN NATURAL GAS PRODUCTION was up 6%. This was primarily driven through the largest natural gas drilling program in the Company’s history with 975 wells and strategic acquisitions. CANADIAN CRUDE OIL PRODUCTION was up 7%. Growth was primarily organic with a record 642 net wells targeting crude oil. Using our lower- risk exploitation approach we achieved a 95% success rate on this program. TOTAL PRODUCTION increased by 8% to average 553 mboe/d. NORTH SEA CRUDE OIL VOLUMES were up 6% due to the combination of an active exploitation program and the full year impact of a property acquisition made in 2004. OFFSHORE WEST AFRICA VOLUMES essentially doubled through the additional drilling of wells at our East Espoir Field and the commissioning of the deepwater Baobab Field, both located in Côte d’Ivoire. The Baobab Field represented the Company’s ﬁ rst deepwater development and was completed in a cycle time of only 4.5 years from initial discovery to ﬁ rst production. OUR PROJECT INVENTORY WAS STRENGTHENED DURING 2005 AS FOLLOWS: • Total landholdings, the input to sustainable conventional growth, increased during the year. As the second largest landholder in the WCSB, it provides us with leverage in most play types found in the basin. • The success of our heavy crude oil marketing plan provided the conﬁ dence to announce the planned, stepwise, development of 300 mbbl/d of new in-situ production over the next several years. • Secondary and enhanced recovery schemes are working at Pelican Lake in Alberta, increasing the potential of this large proliﬁ c ﬁ eld. • Additional phases of development were announced for the Horizon Project targeting up to 500 mbbl/d of production from our oil sands mining leases. • We are reviewing a second bitumen upgrader, in addition to the one integrated with the Horizon Project was announced in tandem with our in-situ developments. Implementation of cost control schemes such as gasiﬁ cation technologies in our oil sands developments is planned. • We captured a new exploitation development of a proved light crude oil ﬁ eld located offshore Gabon. Our disciplined approach continues to deliver strong production volumes at a low cost. The Horizon Oil Sands Project THE HORIZON OIL SANDS PROJECT (“Horizon Project”) represents a world class crude oil development with the following characteristics: • Low geological risk as it is delineated by several hundred stratigraphic wells. We know the resource base and its characteristics. • No production declines normally associated with conventional crude oil and natural gas operations. Production is sustainable; literally, for decades to come. • Bitumen is upgraded on-site to a light sweet synthetic crude oil that is sold at a premium to WTI during 2005. • Only reliable, proven technologies have been utilized. Due to minimal capital reinvestment requirements, this translates into consistent high free cash ﬂ ow generation capability for decades to come. OUR DISCIPLINED APPROACH to this development is being leveraged to its utmost. Prior to sanctioning, we spent 4 years and over $400 million to understand what we wanted to build and how we wanted to build it. This investment was well worth the effort. It helped us to achieve cost certainty in the form of targeting 68% of construction costs under ﬁ xed price bids, a ﬁ rst in the oil sands industry. DURING 2005 we made signiﬁ cant headway on construction activities, accomplishing about 19% of Phase 1 construction by year end. It is still early, but we remain on-time and on-schedule. Many of the foundations were completed and all winter-critical path items remained on track. We target to be approximately 55% completed by the end of 2006. (cid:52)(cid:33)(cid:50)(cid:39)(cid:37)(cid:52)(cid:37)(cid:36)(cid:0)(cid:36)(cid:33)(cid:41)(cid:44)(cid:57)(cid:0)(cid:48)(cid:50)(cid:47)(cid:36)(cid:53)(cid:35)(cid:52)(cid:41)(cid:47)(cid:46) (cid:8)(cid:66)(cid:66)(cid:76)(cid:0)(cid:51)(cid:35)(cid:47)(cid:15)(cid:68)(cid:9) (cid:0)(cid:52)(cid:33)(cid:50)(cid:39)(cid:37)(cid:52)(cid:37)(cid:36)(cid:0)(cid:33)(cid:46)(cid:46)(cid:53)(cid:33)(cid:44)(cid:0)(cid:48)(cid:50)(cid:47)(cid:36)(cid:53)(cid:35)(cid:52)(cid:41)(cid:47)(cid:46) (cid:8)(cid:77)(cid:77)(cid:66)(cid:66)(cid:76)(cid:0)(cid:51)(cid:35)(cid:47)(cid:9) (cid:21)(cid:16)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:21)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:20)(cid:16)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:21)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:19)(cid:16)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:21)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:18)(cid:16)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:21)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:17)(cid:16)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:21)(cid:16)(cid:12)(cid:16)(cid:16)(cid:16) (cid:16) (cid:48)(cid:40)(cid:33)(cid:51)(cid:37)(cid:0)(cid:21)(cid:10) (cid:48)(cid:40)(cid:33)(cid:51)(cid:37)(cid:0)(cid:20)(cid:10) (cid:17)(cid:24)(cid:16) (cid:17)(cid:22)(cid:18) (cid:17)(cid:20)(cid:20) (cid:17)(cid:18)(cid:22) (cid:17)(cid:16)(cid:24) (cid:25)(cid:16) (cid:23)(cid:18) (cid:21)(cid:20) (cid:19)(cid:22) (cid:17)(cid:24) (cid:16) (cid:48)(cid:40)(cid:33)(cid:51)(cid:37)(cid:51)(cid:0)(cid:18)(cid:15)(cid:19) (cid:48)(cid:40)(cid:33)(cid:51)(cid:37)(cid:0)(cid:17) (cid:18)(cid:16)(cid:16)(cid:24) (cid:18)(cid:16)(cid:16)(cid:25) (cid:18)(cid:16)(cid:17)(cid:16) (cid:18)(cid:16)(cid:17)(cid:17) (cid:18)(cid:16)(cid:17)(cid:18) (cid:18)(cid:16)(cid:17)(cid:19) (cid:18)(cid:16)(cid:17)(cid:20) (cid:18)(cid:16)(cid:17)(cid:21) (cid:18)(cid:16)(cid:17)(cid:22) (cid:18)(cid:16)(cid:17)(cid:23) (cid:18)(cid:16)(cid:17)(cid:24) (cid:18)(cid:16)(cid:17)(cid:25) (cid:18)(cid:16)(cid:18)(cid:16) (cid:10)(cid:0)(cid:73)(cid:78)(cid:67)(cid:76)(cid:85)(cid:68)(cid:69)(cid:83)(cid:0)(cid:73)(cid:78)(cid:13)(cid:83)(cid:73)(cid:84)(cid:85)(cid:0)(cid:80)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:70)(cid:79)(cid:82)(cid:0)(cid:34)(cid:73)(cid:82)(cid:67)(cid:72)(cid:0)(cid:45)(cid:79)(cid:85)(cid:78)(cid:84)(cid:65)(cid:73)(cid:78) OUR CREATIVE LABOUR strategy was a further outcome from this preplanning. The addition of an on-site 737–capable airstrip has enabled workers from all across Canada to participate in our managed open site. This expanded access to labour is a critical success factor as the construction effort continues. Our ﬁ rst class camp facilities augment this plan. WE ARE REVIEWING the option of combining Phases 2 and 3 into one phase bringing total production to approximately 232 mbbl/d by approximately 2011. Doing so may enable us to keep more trained workers remaining on site in a competitive market. Financially we are capable of accomplishing it. We will fully investigate the merits of this and will decide by early 2007. WE ANNOUNCED ADDITIONAL FUTURE PHASES 4 AND 5 late in 2005 which will seek to optimize the development of this vast asset base. These phases, augmented by bitumen feedstock from in-situ operations, will result in total production capacity of about 500 mbbl/d of light sweet synthetic crude oil from the leases by 2017. Horizon will add signiﬁ cant shareholder value for decades to come. Canadian Natural Upgrader and In-situ Developments CANADIAN NATURAL OWNS A TREMENDOUS ASSET BASE in the heavy crude oil and oil sands regions of Canada. The challenge has been to develop these assets in a methodical and disciplined manner due to the limitations imposed by reﬁ ner conversion capacity. OUR HEAVY CRUDE OIL MARKETING STRATEGY seeks to overcome this challenge. We have been aggressive in the execution of this strategy over the last two years. We are now the largest blender of heavy crude oil in Canada at about 140 mbbl/d during 2005, creating products that are usable by more reﬁ ners within our traditional geographic market. We support various pipeline initiatives to expand the geographic reach of our marketing efforts, and in 2005 we committed 25 mbbl/d to the Coriscana Pipeline delivering our heavy crude oil directly into the US Gulf Coast where signiﬁ cant conversion capacity exists. The ﬁ nal leg of the strategy is to encourage the creation of more conversion capacity in our markets. (cid:34)(cid:73)(cid:82)(cid:67)(cid:72)(cid:0)(cid:45)(cid:79)(cid:85)(cid:78)(cid:84)(cid:65)(cid:73)(cid:78) (cid:8)(cid:55)(cid:14)(cid:0)(cid:40)(cid:79)(cid:82)(cid:73)(cid:90)(cid:79)(cid:78)(cid:9) (cid:33) (cid:52) (cid:50) (cid:37) (cid:34) (cid:44) (cid:33) (cid:46) (cid:33) (cid:55) (cid:37) (cid:40) (cid:35) (cid:52) (cid:33) (cid:43) (cid:51) (cid:33) (cid:51) (cid:39)(cid:82)(cid:69)(cid:71)(cid:79)(cid:73)(cid:82)(cid:69) (cid:43)(cid:73)(cid:82)(cid:66)(cid:89) THE ECONOMICS OF THE UPGRADER ARE ROBUST; in a US$35/bbl WTI price world we would expect to increase per barrel net backs by approximately US$9.50 over selling bitumen alone. Additionally, since we will be selling a light crude oil capable of feeding most reﬁ neries we reduce the impacts of existing heavy crude oil conversion capacity limits. THE PROPOSED CANADIAN NATURAL UPGRADER represents the logical extension of this third effort and leverages the upgrading and project management technical expertise from our Horizon Project. We will complete a Scoping Study to determine the optimal technology, location, size and product output of this heavy oil upgrader in 2006. If approved, we will utilize the same disciplined approach that is making the Horizon Project so successful – front end engineering and design. (cid:48)(cid:82)(cid:73)(cid:77)(cid:82)(cid:79)(cid:83)(cid:69) (cid:48)(cid:82)(cid:73)(cid:77)(cid:65)(cid:82)(cid:89) (cid:40)(cid:69)(cid:65)(cid:86)(cid:89)(cid:0)(cid:47)(cid:73)(cid:76) (cid:34)(cid:35) (cid:33)(cid:34) (cid:51)(cid:43) OUR PRIMROSE, KIRBY, GREGOIRE AND BIRCH MOUNTAIN in-situ opportunities headline a vast oil sands opportunity for our shareholders. We will develop these and other properties to provide feedstock for our upgraders. We target to bring on about 300 mbbl/d of new in-situ production in manageable, stepwise increments of 30 mbbl/d over the next several years. Lightening the mix reduces marketing risks and increases netbacks. The Deﬁned Plan for Proﬁtable Future Growth OUR PROJECT INVENTORY HAS NEVER BEEN STRONGER and this affords us the ability to add signiﬁcant transparency to our deﬁned growth plan. We articulate the optimal 5-year organic development strategy for every product and every basin in which we operate. Our knowledge of our basins, historic track records and lower-risk exploitation focus facilitate a realistic determination of base production declines, and results of the planned drill program. Major new project development expenditures and a conservative price deck of ﬂat US$35/bbl WTI are then applied to obtain a ﬁnancial view of the Company. EVEN WITH CONSERVATIVE PRICING we remain well within our targeted ﬁnancial ratios. Opportunistic acquisitions have always been a key element of our strategy, and we have diligently altered our organic plans to accommodate them. That is the strength of owning and operating your project portfolio – you have the ﬂexibility to alter plans on short notice. While current pricing of assets remain outside of our parameters, we maintain ﬁnancial ﬂexibility in our plan to accommodate such acquisitions should they become available. OUR SKILL SET CONTINUES TO EVOLVE enabling us to take on larger and more complex projects. We have developed deep water development proﬁciency, upgrading expertise and mega project management skills. Our team has evolved to maximize the value of our asset base. OUR FINANCIAL STRENGTH will allow us to continue to add to this expertise and to our project portfolio. BY 2013, WE EXPECT OUR PRODUCTION LEVELS TO SIGNIFICANTLY INCREASE. Further given the nature of the additions we are making, our production mix will provide higher realizations and stronger cash ﬂows. This will make Canadian Natural a larger more sustainable company throughout the resource price cycle. Building an even stronger, more sustainable Canadian Natural. ��Maintaining discipline. We do not compromise on our values and do not chase commodity prices. Recent high commodity prices have shifted our short-term emphasis solely into organic growth as acquisitions are expensive. Every well we drill must still pass hurdle rates similar to prior years. Our major developments are still subject to extensive front end design prior to construction. Maintaining discipline is a core competency. 24 The Plan: Environment, Health & Safety and Community 26 The Assets: Review of Assets 40 The Assets: Year-End Reserves 45 Management’s Discussion & Analysis Auditors’ Report / Consolidated 74 Financial Statements Supplementary Oil & Gas Information 97 102 Ten-Year Review 104 Corporate Information Financial Highlights FINANCIAL ($ millions, except per share data) Revenue, before royalties Net earnings Per common share – basic (1) – diluted (1) Adjusted net earnings from operations (2) Per common share – basic (1) – diluted (1) Cash flow from operations (2) Per common share – basic (1) – diluted (1) Capital expenditures, net of dispositions Long-term debt Shareholders’ equity OPERATING Daily production, before royalties Crude oil and NGLs (mbbl/d) North America North Sea Offshore West Africa Natural gas (mmcf/d) North America North Sea Offshore West Africa Barrel of oil equivalent (mboe/d) Average prices before royalties (3) Crude oil and NGLs ($/bbl) North America North Sea Offshore West Africa Company average Natural gas ($/mcf) North America North Sea Offshore West Africa Company average 2005 2004 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 10,107 1,050 1.96 1.95 2,034 3.79 3.78 5,021 9.36 9.33 4,932 3,321 8,237 222 68 23 313 1,416 19 4 1,439 553 39.62 66.57 59.91 46.86 8.65 3.17 5.91 8.57 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 7,547 1,405 2.62 2.60 1,405 2.62 2.60 3,769 7.03 6.98 4,633 3,538 7,324 206 65 12 283 1,330 50 8 1,388 514 33.16 51.37 49.05 37.99 6.61 3.73 5.25 6.50 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2003 6,155 1,403 2.62 2.53 987 1.84 1.80 3,160 5.88 5.76 2,506 2,748 6,006 175 57 10 242 1,245 46 8 1,299 459 29.40 42.00 36.47 32.66 6.34 3.03 4.37 6.21 (1) Restated to reflect two-for-one share splits in May 2004 and May 2005. (2) Adjusted net earnings from operations and cash flow from operations are non-GAAP terms that represent net earnings adjusted for certain items of a non-operational and non-cash nature. The Company evaluates its performance based on these measures. Adjusted net earnings from operations and cash flow from operations may not be comparable to similar measures presented by other companies. (3) Including transportation costs and excluding risk management activities. 4 Financial Highlights 2005 represented a record year in terms of production, reserves and cash ﬂ ow. We remain poised for continued delivery. 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The reserves shown for bitumen and SCO are not additive. THE PEOPLE Our multi disciplinary teams leverage the skills of all members to deliver the Plan. THE PLAN We develop strategies for every facet of our operations to optimize our resources and control costs. THE ASSETS Our asset portfolio is deep, facilitating nimble reactions to changing business environments and opportunistic acquisitions. 6 Letter to Shareholders ALLAN P. MARKIN Chairman N. MURRAY EDWARDS Vice-Chairman JOHN G. LANGILLE Vice-Chairman STEVE W. LAUT President & Chief Operating Ofﬁ cer Letter to Shareholders For Canadian Natural, 2005 was another exceptionally successful year. On the conventional side of the business, each of our four per-share business metrics have increased as shown below, adding to the substantial gains during the last 5 years. 1–Year 5–Year Growth per share in: 8% Net production 8% Net proved and probable reserves 33% Cash ﬂ ow NAV of conventional reserves and land (1) 82% 57% 66% 132% 194% Over and above the conventional side of the business, we sanctioned Phase 1 of the Horizon Oil Sands Project (“Horizon Project”) in early 2005, obtained lump sum bids on a substantial portion of Phase 1 construction costs and completed 19% of the construction effort. The Horizon Project will add signiﬁ cant value for shareholders, with commissioning of Phase 1 targeted at 110,000 barrels per day capacity of light sweet synthetic crude oil in the second half of 2008 (and ultimately targeted at 232,000 barrels per day as Phase 2 and 3 are commissioned) with no declines expected for decades to come. A year-end independent evaluation resulted in the booking of 3.4 billion barrels of gross proved and probable bitumen reserves for the Horizon Project. We also added signiﬁ cant transparency to the longer term growth prospects of the Company by articulating our extensive in-situ oil sands plans and proposed heavy crude oil upgrader project as well as Phases 4 and 5 for the Horizon Project. These proposed enhancements: STRATEGIES AND THE BUSINESS ENVIRONMENT During 2005, commodity prices remained strong, enabling us to reduce long-term debt by approximately $400 million while both spending $1.3 billion on construction of the Horizon Project and delivering on our base conventional business. This left our debt to book capitalization at only 29%, or 5 percentage points better than where we entered the year. However, this robust price environment has also resulted in a high demand for services and many cost control challenges. During 2005, the industry set records for active drill rigs, meters drilled and the numbers of wells drilled in western Canada. This combined with the general business and construction boom in western Canada places a high demand on the labour force and creates signiﬁ cant cost inﬂ ation for services. Many oilﬁ eld services and drilling day rate costs have increased by up to 30% over the past year. High activity levels have also resulted in a near doubling in per-hectare land acquisition costs. As such, maintaining discipline remains a priority. By adhering to our strategies, we have been able to mitigate much of these cost increases, maintaining our cost competitiveness. For example, our production expense and our ﬁ nding and onstream costs increased at below industry average rates, despite record drilling by the Company and an increase in total land ownership. This reﬂ ects the execution of a well thought out multi-year development and drilling plan and our domination of core region infrastructure, which facilitates low-cost reserve additions and synergistic cost savings across ﬁ elds. • Provide a natural migration of professional engineering and project management skills as well as construction workers; Canadian Natural’s strategy allows us to allocate capital to maximize returns and remains predicated on: • Unlock our vast heavy crude oil resource value potential; • Capture a major portion of the value chain in the heavy crude oil business; and, • Maintaining a large project portfolio in every basin we operate to enable us to continually high-grade current developments; • Maintaining balance in our product mix, project time • Control operating costs through targeted application of horizons and ﬁ nancing strategies; gasiﬁ cation technologies. (1) Discounted value of conventional reserves and undeveloped land less net debt. Letter to Shareholders 7 During 2005, our growth was primarily achieved though the drillbit as property acquisition costs remained high. This program resulted in crude oil production increases of 11% and natural gas volumes increases of 6% in Canada. • Continually balancing between acquisitions and exploration, while remaining focused on low-cost exploitation; • Identifying and completing acquisitions if they are cost effective and provide strategic upside; and, • Controlling costs through area knowledge and domination of core focus regions. 2005 CONVENTIONAL OPERATIONS IN REVIEW During 2005, our growth was primarily achieved through the drillbit as property acquisition costs remained high. Our drilling program resulted in crude oil production increases of about 11% over 2004 levels and natural gas volume increases of 6% in Canada. Expenditures on conventional operations represented about 68% of the cash ﬂ ow generated by them. INTERNATIONAL Our International operations represented a signiﬁ cant portion of that growth. Average light crude oil production in the North Sea increased by about 4 thousand barrels per day or 6% from the previous year, the result of both an active in-ﬁ ll drilling program and the full year impact of an acquisition made in mid-2004. We have sufﬁ cient exploitation projects in inventory to maintain and marginally grow volumes for the next several years on a very economic basis. Our Offshore West African crude oil production volumes from Côte d’Ivoire effectively doubled from 11.6 thousand barrels per day in 2004 to average 22.9 thousand barrels per day in 2005. This reﬂ ected an active in-ﬁ ll drilling program to access previously untapped portions of the East Espoir development as well as the commencement of production from our ﬁ rst deepwater development at Baobab. First production from Baobab was completed in just 4.5 years from ﬁ rst discovery – an excellent cycle time for deepwater developments. This achievement in our ﬁ rst deepwater development speaks to the technical expertise that we have developed and the diligence we demand in delivery. We expect continued growth in Offshore West Africa as our West Espoir satellite development is completed in the second half of 2006 and as we forecast to commence production in late 2008 from our recently acquired Olowi Field located Offshore Gabon. The Olowi Field was acquired during the fourth quarter of 2005 and we ﬁ led our development plan with the Government of Gabon by the end of the year. In early 2006 we received required approvals and have already commenced the engineering tender process. The new opportunity created with the Olowi acquisition allows us to utilize our Offshore West Africa experience to quickly bring Olowi onstream. NORTH AMERICAN NATURAL GAS We remain a signiﬁ cant producer of natural gas in Canada, representing approximately 8.5% of western Canadian output. Further, our land base represents the second largest portfolio in the industry, meaning that we have exposure to virtually every play type found in the basin. As our largest single product offering at about 43% of our production mix in 2005, production increased by about 6% over 2004 levels driven largely by record natural gas drilling activity and the full year inclusion of property acquisitions made in 2004. Most of the 2005 production growth was centered in Northwest Alberta where we continue to build on our strong base of assets acquired in 2002. This core region, along with our Northeast British Columbia core region, has the ability to drive corporate natural gas production growth of 3% to 5% for at least the next 5 years. Our Northern Plains core region will provide relatively ﬂ at to slightly declining production while the Southern Plains region has potential to grow volumes both through its shallow and coal bed methane natural gas programs. Our 5-year deﬁ ned plan incorporates a disciplined low-cost exploitation methodology for each of our natural gas assets assuming prices well below today’s market pricing. NORTH AMERICAN CRUDE OIL AND NGLS Success in our Canadian crude oil operations continued with production increasing by over 7% from 2004 levels. At our Pelican Lake Field we reversed years of production declines through a successful waterﬂ ood rollout in portions of the ﬁ eld. The development of Pelican Lake has occurred in a very disciplined manner. We experimented with different approaches 8 Letter to Shareholders (cid:47)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195) (cid:173)(cid:147)(cid:76)(cid:156)(cid:105)(cid:201)(cid:96)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:120)(cid:120)(cid:206) (cid:120)(cid:163)(cid:123) (cid:123)(cid:120)(cid:153) (cid:123)(cid:211)(cid:163) (cid:206)(cid:120)(cid:153) to the waterﬂ ood, initially obtaining a tripling of production with water cuts of 70%-80%. Our current approach, however, is providing per well crude oil production increases of 10-15 times with water cuts of only 10%. This application of waterﬂ ood may ultimately double expected recovery factors from the reservoir. This same diligence will be used in our current testing of polymer ﬂ oods, which have the potential to again signiﬁ cantly increase recovery factors from the Field. Based on our success, we now expect to ramp production levels at this Field and signiﬁ cantly extend Field life. Our conventional heavy crude oil production grew throughout the year following the most active drilling program in our history. Similar to our natural gas approach we also have an extensive 5 year development plan for these assets allowing us to maintain and grow volumes in a very disciplined manner. We continually leverage our large infrastructure and land base to control costs. Our thermal in-situ oil sands developments also continue to outperform our expectations. The Primrose development continued with the addition of 109 net new wells, which yielded production increases of approximately 22% over 2004 levels. Overall, the new Primrose well pads continue to produce at rates approximately 17% better than expected. The Primrose North expansion also continued on time and on budget with ﬁ rst crude oil production coming on stream in early 2006. This expansion will add about 30,000 barrels per day to exit rate production capacity in 2006. Our heavy crude oil assets in Alberta represent a substantial opportunity. We have extensive landholdings with both primary and in-situ oil sands areas that continue to deliver signiﬁ cant returns. However, in order to capitalize on these assets in a disciplined manner the Company has developed a strong marketing plan. We ﬁ rst articulated our heavy crude oil marketing strategy in 2003 and we have since been successfully executing against that plan. At about 140,000 barrels per day, Canadian Natural is now the largest blender of crude oils in western Canada. This blending strategy represents the ﬁ rst element of the marketing strategy and allows us to sell product to an expanded group of reﬁ ners within our traditional geographic markets. The blending strategy has evolved to allow for multiple blends that can be changed as markets for various forms of diluents and ﬁ nal product price differentials change. The second element of this strategy was to support various pipeline initiatives to expand geographic markets. During 2005 we committed to a 25,000 barrels per day shipping agreement on the reversal of the Corsicana line, which will enable us to deliver heavy crude oil directly into the US Gulf Coast. This market is important as much of the heavy crude oil conversion capacity in the United States is located in the region and heavy crude is sold for a premium to what is received in our traditional US Midwest markets. We continue to pursue similar opportunities to other markets in a disciplined manner. Finally, with respect to the pursuit of increased heavy crude oil conversion capacity, we proposed in late 2005 that we will leverage our technical expertise, project management skills and ﬁ nancial capability, which, coupled with our strong asset base would enable us to build our own upgrader in Alberta. To that end we are currently engaged in a scoping study that will deﬁ ne the location, nature and technologies to be utilized in this project. This proposed upgrader is targeted to be onstream in 2012, and will facilitate an additional 300,000 barrels per day of incremental bitumen production in a stepwise and disciplined manner over the next decade selling a portion of it as light crude oil rather than lower priced heavy crude oil. Capturing substantially more of the heavy crude oil value chain through upgrading not only increases realizations, it also reduces marketing and cash ﬂ ow risks as it expands markets for the bitumen and eliminates the impact of quality differentials. HORIZON OIL SANDS PROJECT This bitumen mining and upgrader project made signiﬁ cant progress during the year following the sanctioning for Phase 1 by our Board of Directors in February 2005. This approval was predicated on a disciplined process in which signiﬁ cant front end Letter to Shareholders 9 We believe that Canadian Natural has the People, the Plan and the Assets to continue to deliver shareholder value for years to come. We remain committed to “develop people to work together to create value for the Company’s shareholders by doing it right with fun and integrity”. engineering efforts afforded us the ability to obtain the majority of the Phase 1 construction costs under lump sum bids. This high degree of cost certainty was augmented by an expanded hedging program, which ensured that adequate free cash ﬂ ow to complete the four year construction effort would be available. While there was an opportunity cost associated with the hedging program, it was the combination of these two elements that enabled the Company to retain a 100% working interest in the Horizon Project without having to compromise on any of our conventional developments. Four years and $400 million worth of front end engineering have provided Canadian Natural with a strong understanding of what we are building and, just as importantly, how we are going to build it. We have forged relationships with a variety of contractors from around the world and together have provided a strong deﬁ nition of the construction execution plan. Further this high project deﬁ nition reduces the risks associated with late engineering or “scope” changes which have historically resulted in signiﬁ cant cost revisions for oil sands builders. Finally, we have developed a unique and creative labour strategy that has enabled workers of all labour afﬁ liations from across Canada to participate in the construction effort. This strategy is facilitated through our ﬂ y in/ ﬂ y out capability from our on-site air strip. Today, workers from several provinces in Canada regularly ﬂ y to our site and home again on various shifts which accommodate their lifestyles. Starting from a cleared site of dirt at the beginning of the year, we exit 2005 with approximately 19% of the construction effort completed. Deep underground facilities are installed, many of the footings are in place and much of the large prefabricated units are complete with several already being delivered to site. Although it is still early, we remain on schedule and on budget. Our lump sum contractors are motivated to seek creative ways to build their portions more effectively. One opportunity identiﬁ ed by them was the exploitation of an expected lull in industry construction activity in 2006 which should make additional workers available to industry. As such, they requested and we approved the acceleration of $400 million of 2007 spending into 10 Letter to Shareholders 2006, as long as they did not deviate from the base requirement of having 80% of engineering completed prior to construction. As a result, we expect to exit 2006 in excess of approximately 55% of the construction effort completed. In all, we remain on budget and on schedule for ﬁ rst oil in 2008. Further, in concert with our in-situ oil sands development plan, we announced the parameters of Phase 4 and Phase 5 expansions of the Horizon Project which will leverage the remainder of our mineable leases. We now target to produce in excess of 500,000 barrels per day of light sweet synthetic crude oil from the Horizon leases by approximately 2017, with no production declines for decades to come. This is truly a world class development opportunity and we intend to follow the same disciplined approach that is currently being utilized on Phase 1. (cid:10)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:202)(cid:125)(cid:192)(cid:156)(cid:195)(cid:195)(cid:202)(cid:86)(cid:156)(cid:152)(cid:219)(cid:105)(cid:152)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:202)(cid:171)(cid:192)(cid:156)(cid:219)(cid:105)(cid:96)(cid:202)(cid:192)(cid:105)(cid:195)(cid:105)(cid:192)(cid:219)(cid:105)(cid:195) (cid:173)(cid:147)(cid:147)(cid:76)(cid:156)(cid:105)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:93)(cid:110)(cid:228)(cid:123) (cid:163)(cid:93)(cid:200)(cid:199)(cid:123) (cid:163)(cid:93)(cid:120)(cid:211)(cid:200) (cid:163)(cid:93)(cid:123)(cid:153)(cid:199) (cid:163)(cid:93)(cid:211)(cid:123)(cid:206) (cid:10)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:202)(cid:125)(cid:192)(cid:156)(cid:195)(cid:195)(cid:202)(cid:86)(cid:156)(cid:152)(cid:219)(cid:105)(cid:152)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:202)(cid:171)(cid:192)(cid:156)(cid:219)(cid:105)(cid:96)(cid:202)(cid:62)(cid:152)(cid:96) (cid:171)(cid:192)(cid:156)(cid:76)(cid:62)(cid:76)(cid:143)(cid:105)(cid:202)(cid:192)(cid:105)(cid:195)(cid:105)(cid:192)(cid:219)(cid:105)(cid:195) (cid:173)(cid:147)(cid:147)(cid:76)(cid:156)(cid:105)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:211)(cid:93)(cid:120)(cid:200)(cid:211) (cid:211)(cid:93)(cid:206)(cid:206)(cid:228) (cid:211)(cid:93)(cid:163)(cid:163)(cid:110) (cid:163)(cid:93)(cid:199)(cid:153)(cid:163) (cid:163)(cid:93)(cid:123)(cid:199)(cid:153) (cid:10)(cid:143)(cid:156)(cid:195)(cid:136)(cid:152)(cid:125)(cid:202)(cid:47)(cid:45)(cid:56)(cid:202)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:105) (cid:173)(cid:10)(cid:102)(cid:201)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:93)(cid:202)(cid:62)(cid:96)(cid:141)(cid:213)(cid:195)(cid:204)(cid:105)(cid:96)(cid:202)(cid:118)(cid:156)(cid:192)(cid:202)(cid:211)(cid:228)(cid:228)(cid:123)(cid:202)(cid:62)(cid:152)(cid:96)(cid:202)(cid:211)(cid:228)(cid:228)(cid:120)(cid:202)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:202)(cid:195)(cid:171)(cid:143)(cid:136)(cid:204)(cid:195)(cid:174) (cid:211)(cid:120)(cid:176)(cid:200)(cid:206) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:200)(cid:176)(cid:206)(cid:123) (cid:163)(cid:163)(cid:176)(cid:199)(cid:228) (cid:153)(cid:176)(cid:120)(cid:110) (cid:120)(cid:199)(cid:176)(cid:200)(cid:206) DEFINED PLAN The Canadian Natural team is proud to be able to provide a transparent strategy and growth proﬁ le to its shareholders. We still target to grow each of our four metrics by an average of 10% per annum and believe that we have the assets to deliver on it. Financially, we stress tested our plan at US$35 WTI per barrel crude oil prices and would still remain below our targeted ﬁ nancial strength ratios. As such, we do not have to compromise on our basic strategies and retain additional ﬁ nancing capacity should compelling acquisition opportunities present themselves. Of course, as has occurred in the past, our disciplined allocation of capital may result in a shift between organic projects and acquired production as is prudent, should such an opportunity arise. In addition to the production growth aspect of the plan, the migration of the production mix from one dominated by natural gas and heavy crude oil to one dominated by light crude oil and natural gas means that the economic sustainability of the organization is enhanced throughout the business cycle. Reducing overall exposure to heavy crude oil differentials and avoiding reliance on third parties to develop the markets for our products was a key consideration in our plans. We have taken control of the plan in a ﬁ nancially and operationally disciplined manner and will create a company and deﬁ ned plan that: • Leverages the low-cost and lower-risk exploitation nature of the Alberta oil sands with light crude oil netbacks; • Utilizes an exceptionally large land base/infrastructure to deliver increased natural gas volumes in an economic manner; • Leverages the exploitation expertise developed in western Canada into the United Kingdom North Sea basin to create new value for shareholders; and, • Fully exploits the offshore expertise developed in the North Sea, and combined with the strong relationships developed in Offshore West Africa enables us to identify appropriate new exploration and exploitation opportunities in one of the most proliﬁ c light crude oil basins in the world. Management would like to thank our team for continuing to deliver the Plan. We would also like to extend our welcome to new Directors standing for election this year, the Honourable Gary A. Filmon, P.C., O.M., and Mr. Norman F. McIntyre. We believe that Canadian Natural has the People, the Plan and the Assets to continue to deliver shareholder value for years to come. As a team, we remain committed to “developing people to work together to create shareholder value by doing it right with fun and integrity”. ALLAN P. MARKIN Chairman N. MURRAY EDWARDS Vice-Chairman JOHN G. LANGILLE Vice-Chairman STEVE W. LAUT President & Chief Operating Ofﬁ cer Letter to Shareholders 11 The People Excellent people are critical to the success of any organization. The Company strives to achieve a balance of technical skills, leadership, and a strong organizational culture. Even with the rapid expansion of our team, we have retained this balance. Our technical skills have grown as we have expanded into new basins and products. For example, it was the upgrading expertise and mega-project management skills that we have developed through the Horizon Project that afford us the potential to undertake new initiatives such as the Canadian Natural Upgrader for our in-situ oilsands developments. These are the people that make our team. Together we deliver the “Plan”, converting our strong assets into shareholder value. Lonnie Abadier, Walday Abeda, Hazel Aberdein-Quirie, Mona Abravesh, Marbella Abuin, Janine Adams, Michael Adams, Steve Adams, Steven Adams, James Agate, Jennifer Ahern, Sarshar Ahmad, Garrisen Ailsby, John Aina, John Aina, Fiona Jean Aitken, Sina Akinsanya, Joseph Albano, Chris P Alderson, Andrew Alexander, Bruce Alexander, Gregory Alexander, Elena Algazina, Mohieddin Alghazali, John Allan, Selena Allan, Jill Allen, John Allen, Simon Allerton, William Allerton, Devin Allibone, Karen Almadi, Eva D Almeida, Gordon Almond, Robert Almond, Jocelyn Alonso, Nelson Alook, Cindy Alpaugh, Ulises Amador, Joann Aman, Clark Ambler, Donald Ames, Sylvia Anaka, Eric Andersen, Grayson Andersen, Jan Andersen, Troy Andersen, Bruce Anderson, Georgina Anderson, Greg Anderson, Jeremy Anderson, Kelvin Anderson, Larry Anderson, Leonard Anderson, Murray Anderson, Paula Anderson, Perri Anderson, Richard Anderson, Peter Andrekson, Janet Andrew, Bob Andrews, Todd Andrews, Sherley Angers, Carolyn Angus, Brian Antoni, Rogerio B Antonio, Kathy Antonishyn, Shelley Antonuk, Jim Archibald, John Argan, James Arkley, Anthony Armstrong, Darryl Armstrong, Randall Armstrong, Rob Armstrong, Paul Arsenault, Niels Arveschoug, Jim Asmus, Jacqueline N’Goran Asso, Sialla Victoire Assohou, Francklin Assoko-Mve, Maguy Aude Atheba, John Atkinson, Nicole Atkinson, Gordon Au, Maurice Aubin, Jason Auch, Bernard Auger, Richard Augustyn, Colin Avison, Eustace Azim, Adrian Baciulica, August Baier, Dave Baier, Janice Baik, Michael Baik, Dwayne Bailer, Rod Bailer, Leon Bakaas, Chris Baker, Sharon Baker, Patricia Bakker, Reginald Baldock, Christopher Baldwin, Mark Baldwin, Vaughn Baldwin, Joel Balkam, Colin Ball, Gary Ballas, Ronnie Ballas, Sheldon Ballas, Mamadou Bamba, Neville Banak, Darwin Banash, Rechelle Baniqued, Bob Banks, Teresa Banny, Inge Bantli, Garry Bardoel, Larry Bardoel, Pamala Bare, Sharon Barker, Stephen Barker, Michael Barnes, Javier Baroja, Kenneth Barrett, Phrona Lisa Barrett, Darcy Barry, Carol Barss, Marty Bartman, Sonia Basati, Julius Bascon, Calvin Bast, Cheryl Bateman, Lisa Bateman, Selena Bath, Brenda Battyanie, Jackie Bauer, Kevin Bauman, Juan Bavaresco, Veronica Bayley, Colin Beaman, Chad Beaton, Aura Beattie, Laurier Beaunoyer, David Bechtel, Chris Becker, Elke Becker, Gurpreet Bedi, Ewan Beenham, Adrian Begley, Loren Behrens, Guy Belanger, Lesley Belcourt, Betty Belenky, Calvin Bell, David Bell, Faye Bell, Jon Bell, Larry Bell, William Bell, Reg Bellanger, Lorne Bellows, Remie Belmonte, Ahmed Bendahmane, Khalida Bendahmane, Brad Bendick, David Bendrey, David Bennington, Shelly Bensmiller, James Bentley, Linda Beresh, Debbie Berg, Lorn Berg, William Berg, Jeffrey Bergeson, David Berlinguette, Henry Berlinguette, Joanne Berrade, Murray Bertsch, Jonathon Best, Stewart Bettinson, Bob Bezpalko, Marc Bickham, Jennifer Bidlake Schroeder, Douglas Bielech, Inge A Biener, Bruce Bignell, Rhett Binding, Roger Bintz, Warren Birch, Tim Bird, Hope Bishop, Travis Bishop, Paula Bissell, Peter Bissell, Darwin Bittner, Kevin Bjornstad, Adam Black, Chad Black, David Black, Jennifer Black, Kenneth Blackhall, Kerri Blackmore, Michael Blair, Deana Blais, David Blake, Christopher Blatchly, Parrish Blizard, Ellen Bloomﬁeld, Robin Bly, Allan Boddy, Brad Bodnar, Dennis Boehmer, Michael Boer, Kent Boerrichter, Darcy Boettger, Marty Boggust, Gordon Bohrson, Paul Boileau, Claude Boily, Peter Boisvert, Michael Bolianatz, Greg Bolin, Greg Bolton, Patricia Booklall, Jayne Booth, Karen Booth, Jack Bootsman, Charlene Boraas, Barry Borbely, Adriana Borbon, Albert Bordeleau, Michael Born, Jon Borstel, Prasanta Borthakur, Dave Bosch, Dave Bosek, Greg Boshaw, Keith Bottriell, Suzanne Boudignon, Kari Bouillet, Sheldon Bourassa, Daryl Bourque, Jason Bowers, Jim Bowers, Slade Bowers, Dale Boychuk, Doug Boyd, Patrick Boyd, Randy Boyd, Charline Boyer, Neil Bozak, John Brabec, Dave Bracey, Bryan Bradley, Peggy Bradner, Jan Bradshaw, Marianne Brady, Mary Jane Brady, Linda Bragg, Ralph Brand, Myron Brataschuk, Brad Braun, Colin Brausen, Vincent Breaker, Tara Brechin, Tara Brechin, Sharon Breitkreuz, Leonie Breitling, Joseph Breland, Paul Breland, Roxane Bretzlaff, Denis Brisebois, Robert Brisson, Shawn Brockhoff, Kelly Broda, Brian Brodbin, Ashley Broderick, Dwayne Brodziak, Katherine Brogden, John Brogly, Bill Bromling, Murray Brooker, Dennis Brooks, Carla Brown, Darren Brown, Jeremy Brown, Steve Brown, Robert Brownless, Elizabeth Brownrigg, John Brule, Gordon Bryant, Stewart Buchan, William Buchan, Anna Bucior, Linda Bucke, Natasha Buckland, Gordon Buckshaw, Linda Buczkowski, Malcolm Budd, Raymon Bueckert, Ryan Bulger, Ian Bulloch, Clarence Bur, Trevor Burchenski, Ian Burchette, Jeffrey Burdett, Brent Bureau, Heather Bureau, Keith Bureau, Grant Burgess, Alastair Burke, Crystal Burke, Gayle Burnett, Wendy Bursey, Gerald Burtch, Corinne Burton, Lisa Bush, Rosemary Bussi, Terry Butchart, Jim Butler, Bob Butterworth, Ronald Butts, Leanne Butz, Tricia Butz, Mike Byrtus, Irina Byvald, Joe Cabay, Mark Cadman, James Cadrain, Simon Cains, Laura Calder, Leslie Calder, Patrick Caldwell, Thomas Callaghan, Richard E Calliou, Lynn Callsen, Dean Cameron, Mike Cameron, Rory Cameron, Shirley Cameron, Tavis Cameron, Catherine Campbell, Clayton Campbell, Dean Campbell, Doug Campbell, Earl Campbell, Nancy Campbell, Robert J Campbell, Shawn Campbell, Valerie Campbell, Andre Campeau, Gregory Cane, James M Capjack, John Capstick, Kathleen Carbury, Fred Cardinal, Harley Cardinal, Lee Cardinal, Sharon Cardinal, Wayne Cardinal, Jim Carey, Mary-Ann Carey, Ian Carleton, Wes Carlson, Daryl Carlton, Leslie Carlyle-Ebert, Albert Caron, Murrey W Carpendale, Kim Carrol, Eduardo Cartaya, Marilyn Carter, Gary Case, Mary-Jo Case, Trevor Cassidy, Mike Catley, Steve Caven, Tom Cegielny, Marco Celis, Samuel Cervantes, Sachi Chakravarty, Mark Chalmers, Erin Chamberlain, Joe Chamberlain, Cynthia Chambers, Katrina Chambers, Lise Champagne, Alan Chan, Anly Chan, Jack Chan, Jik Chan, Sarah Chan, Tim Chan, Christina Chang, Calvin Chapman, Melody Chapman, Todd Chapman, Deon Chappell, Harry Chappell, Darryl Charabin, Cynthia Chartrand, Susan Y Chase, Leon Chateauneuf, Siddique Chaudhry, Dawn Chau-Lam, Gary Chaulk, Jackson Chaves, Rinet Maria Chaves-Thissen, Jacinto Cheng, Mike Chernichen, Brian (Chuck) Cherry, Albert Cheung, James Cheung, Sherry Chiang, Gloria Chick, Patricia Childs, Melaine Chin, Sharon Chin, Jamie Chisholm, William Chiverton, Randall Chodzicki, Jessica Choi, Raymond Chong, Wayne Chorney, Lynn Chotowetz, Sherry Chow, Daryl Chrapko, Alphonse Chretien, Ruth Christensen, Marianne Christianson, Steven Christie, Rob Christopher, Andy Chu, Ken Chudleigh, Sharon Chung, Heather Church, Ronni Church, Kadidiatou Cisse, Magda-Christina Ciulavu, Michael Clapham, Bryan Clapperton, William Clapperton, Amanda Clark, Andrea M Clark, Evan Clark, Janice Clark, Evan Clarke, Martha Clarke, Olivia Clarke, Sanja Clarke, Shandon Clarke, William J Clarke, Walter Clarkson, Greg Clegg, George Clutton, Brooke Coburn, Dale Coburn, Judith Cochran, Sabrina Colangelo, Martin Cole, Robin Coles, Elva Coley, Curtis S Collins, Rod Collins, Royston Collison, Ronald Compton, David Conybeare, Brad Cook, Brian Cook, Christopher Cook, Anna Cooke, Bill Cooke, Gary Coombe, Kent Cooper, Tammy Cooper, Jean Corbiere, Elaine Coreman, Rosetta Cormier, James Corner, Rosario Corral, Luis Correal, Jim Corson, Lorenzo Cortes, Neil Cortmann, Harry Costello, Neil Costeloe, Douglas Coull, Kim Coulter, Jack Courchene, Kathryn Courtney, Julie Cousineau, Dave A Cousins, James Coutts, Gordon Coveney, Richard Coward, Keith Cowger, Catherine Cowie, Jonathan Cox, Randy Cox, Wade R Cox, Nigel Crabb, Harry Crabtree, Layne Craig, Ryan Craig, Bruce Crain, Allen Crawford, Bryan Crawford, Marina Crawford, Paul Crawford, Beverley Creed, Leanne Cressman, Donald Cretney, Roger Crichton, David Cridland, Stefan Croft-Bednarski, Christopher Cross, Lloyd Cross, Camille Croteau, Philip Cruickshank, Linda Cruttenden, Anthony Csabay, Will Csanyi, Jeff Cullen, Corinna Culler, Francesca Cultrera, Darrel Cunningham, Davis Cunningham, Arley Currie, David Currie, Brent Curtis, Paul Curtis, DaleS Cusack, Kenneth Cusack, Pat Cusack, Réal Cusson, Midge Cuthill, Don Cutting, Ken Cyr, Andre C DaCosta, Helder J DaSilva, Ivone Elma Malaquias DaSilva, Victor Daboin, Greg Dacyk, Fakhri Dadashov, Gary Dahl, Hamid Dahmani, Eliane Dakaud, Trevo D Dales, Joey Daley, Layne Dalgetty-Rouse, Walter M Danchak, Gene Danyluk, Peter Danyluk, Alan Dar, Eric Dargis, Lynne Darlington, Wigo Dascalescu, Graham Davidson, Marie Davidson, Philip Davidson, Tim Davidson, Todd Davidson, Frank Davis, Graham Davis, Randall Davis, Robert Davis, Sarah Davis, Jeffrey Davison, Peter Davison, Leonard Dawe, Robert Day, Eric de Kock, Douglas De Avila, Ryan De Bruyne, Phil De Gagne, Ryan De Leeuw, Lance De Meillon, David Dean, Harry Dean, Derek Dechaine, Raymond Dechaine, Roland Dechesne, Sheldon DeFord, Mervin J Degenstien, Barbara Deglow, Daniel L Deiana, Bonnie Deis, Natalie Delfs, Gabriel Deliu, Franco Dell’Ovo, Benita De Lorenzo, Brent Delorme, Michael Delorme, Fiona Dempster, Susan Dennis, Shirley Denny, Edward Deren, Tom Dereniwski, Semir Dervovic, Eugenie Dery, Travis Desilets, Michael Des Roches, Laurie A Devey, Wendy De Visser, Robert Dewis, Karen Deyaegher, Vikas Dhawan, Aldo Di Flumeri, Karim Mounian Diallo, Harry Diamantopoulos, Sumara Diaz, Daniel Diaz-De-Leon, Catherine Dicken, Robert Dicken, Garry Dickie, Cameron Dickson, Irene Dikau, Anne Dillon, Michael Dingley, Ashley Dinkel, Ronald Dinkel, Hubert Dinn, Issiaka Diomande, Gayle Dionne, Al Dixon, Kathleen Dixon, Trent Dixon, Denise Dixson, John Dmetruik, Angela Dobb, Leanne Dobson, Linnae Dobson, Edward Dochuk, Alistair Dodds, John Dodman, Erin Doepker, Kelly Doepker, Ritchie Doering, Patrick Dolan, Amy Dolomount, Conrad Dombowsky, Kelly Dombrosky, Brenda Dombrova, Manuel P Domingos, Dan Domke, Kyle Donald, Scott Donaldson, Tim Donkersloot, Tim 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Bernie Persson, Bernard Peterson, Bill Peterson, Brenda Peterson, Douglas Peterson, William S Petlyk, Dino Petrakos, Rick Petrick, Henry Petrie, Rodney Petrie, Lucyna Pettigrew, Marie (Huong) Phan, Bryanne Philibert, Doug Pierce, Frank Pike, Ron Pilisko, Kathy Pinco, Dale Pinder, Alonso Pineda, Dan Pingitore, Barry Pitchford, Edward Pittman, Ted Plouffe, Erwin Po, Imhotep Pocaterra, Donna Poitras, Wade W Poitras, David Pole, Brandy Poliakiwski, Marlene Pollock, Eleanor Polson, Robert Pool, Chris Poole, James Pope, Jason Popko, Carol Porter, Patti Postlewaite, Jeffrey Poth, Terry Potter, Randy Pottle, Ryan Potts, Bruce Powell, Susan Powell, Laurie Power, Lisa Power, Melissa Power, Noleen Pratap, Mike Preece, Travis Prins, Catherine Proctor, Lesley Proctor, Doug Proll, Sarah Proudlock, Jacques J P Proulx, Richard Proulx, Kayla Prowse, Steve Pshyk, John Puckering, Yesid Edgar Puerto, Justyna Puhl, Nam Pui, Leslie Punko, Suniel Puri, Trent Pylypow, Lu Qing, Munawar Quadri, Warren Raczynski, Levente Rado, Gloria E Ragan, Michael Rainey, Yina Raisbeck, Maritess Ramirez, Ruth Ramonas, Matthew Ramsay, Ron Ramsay, Kerri Ramsbottom, Brian Ramsum, Sunita Ranganathan, Dorotea Ranola, Gregory Ransom, Jeremy Ransom, Shauna Rasmussen, Soukseum Rathamone, Stojan Ratkovic, Joan L Rattai, Murray Rattray, Robert Rayner, Blair Read, Teddy Reay, Deston Reber, Duane R Reber, Bernie Redlich, Donald Reed, Kendra Reed, Loreena Reed, Tim Reed, Michael Rees, Irene N Regner, Duncan Rehm, Carmon Reich, Alan Reid, Lilian Reid, Angela Reimer, Rolande Reinboldt, John Reiniger, Phillip Reist, Glenn A Reiter, Wendy Reitmeier, Kelly Rempel, Long Ren, George Renfrew, Alexander Rennie, Dustin Ressler, Russell Retzlaff, Mike Rew, Pat Reynolds, Keith Rhodes, Charles Richards, Andrew T Richardson, Rob Richardson, Wesley Richardson, William Richardson, Andrea Richmond, Lori Richmond, William Richmond, Jeff Riddell, Robert Riddell, Bonnie Ries, Dominic Riley, Dale E Rinas, Carl Ringdahl, Serge Rioux, Tracey Roasting, Jo-Anne Robak, Jimmie Roberts, Andrew Robertson, Dale Robertson, Morag Robertson, Nancy Robertson, Stephen Robertson, Heather Robillard, Aaron Robinson, Amber Robinson, Arlene Robinson, Brian E Robinson, Gene Robinson, Julian Robinson, Scott Robson, Sheila Rodberg, Nenesa Rodelas, Roger Rodermond, Ray Rodh, Ricardo Rodriguez, Roberto Rodriguez, Paul Roett, Dean Rogal, Russell J Rogers, Neil Rogerson, Henry Rojo, Louis L Romanchuk, Dwayne Romanovich, Eduardo Romeo, Joy Romero, Linda Romness, Claude Rondeau, Dennis Ross, Robert Ross, Ron Ross, Graham Rosso, Worley Rosson, Barry Rosychuk, Cheryl Rosychuk, Rick Rosychuk, Reagan L Roszell, Tom Roth, Katarina Rothe, Judy Rotzoll, David Rouleau, Gordon Rourke, Richie Rovere, Natasha Rowden, Scott Rowein, Andrea Roy, Jeff Roy, Zenita Ruda, Colleen Ruggles, Nigel Rusk, Denise Russell, Jylian Russell, Mark Russell, Matthew Russett, Jeff Rutherford, Brian Rutledge, Doug L Rutley, Daniel Ruttan, Mark Rutter, Hal Rutz, David Ruud, Dan Ryan, Rick Rybchinsky, Jeff Ryll, Mikael Sabo, Adam Saby, Gurdip Sahota, Darlene G Sakires, Mourad Salameh, Shahid Saleem, Khaled Saleh, Shahid Salem, Pedro Salomao, Peter Salomon, Gord Salt, Blaine Salzl, E Wayne Sampson, Geoffrey Samuel, Juan Jose Sanchez, Andrea Sanden, David Sanderson, Sandy Sandhar, Darryl Sandquist, Tom Sanelli, Juan Pablo Santini, Rajiv Saran, John C Sargent, Anita Sartori, Greg Sauer, Lisa Saumier, Christine Savary, Brian Saville, Codey Saville, Luc Savoie, William Sawyers, Chris Sayer, Richard Sayer, Ryan Scammell, Robert Schaap, Trevor Schable, Bruce Schade, Judy Schafer, Paul Schaub, Lorne Schaufert, Perry Scheffelmaier, Barry Schellenberg, Mike Schellenberg, Lance Schelske, Sally Schick, Larry Schielke, Darcy Schira, Ronald Schlachter, Mark Schleindl, Helen Schlenker, Tracy Schmaltz, Beat Schmid, Raquel Schmidt, Joseph Schmitz, Melissa Schmitz, Christopher Schneider, Craig Schneider, Darryl Schneider, Paul Schneider, Blaine Schnell, Aaron Schnick, Jack Schnieder, Ronald Schnieder, C Brian Schnurer, Rene Schoch, Stephen Schoﬁ eld, Norm Schonhoffer, Sheldon Schroeder, Michael Schubert, Tricia Schuh, Stephen Schultheiss, Julie Schultz, Lorraine Schwetz, Tony Sciarrabba, Leslie Scory, Curtis Scott, James Scott, John Scott, Judy Scott, Kim Scott, Murray Scott, Ronalda Scott, Rodney Scoville, Gordon Seabrook, Geordie Seaton, Adam Seber, John C Seffern, Brian Segouin, Morley Seguin, Stephen Seguin, Clayton Seifridt, Fraser Selfridge, Kenneth Selman, Conrad Semeniuk, Kevin Semenoff, Roland Senecal, David Sergeant, Edward Serniak, Cindy Severite, Jeremy Seward, Gianni Sgambaro, Mohsen Shaﬁ zadeh, Sanjay Shah, Philip Shankowski, Gilbert Shantz, Raj Sharma, Marilyn Shaw, Dorothy Shea, Robert Shears, David Sheaves, Wayne Sheaves, Ben Shenton, Glenn Sheppard, Robert Sheppard, Tim Sheppard, Ron Sheremeta, Judi Shermerhorn, Jason Sherstabetoff, Annette Shillam, Leonard Shostak, Trent Shwaluk, Melanie Siddon, Patricia Sideen, Ken Siemens, Steve Siemens, Travis Siemens, Wayne Sikorski, Lorraine Silas, Beh Silue, Kevin Simard, Bradley Simonar, Barbara Simpson, Brad Simpson, Patrick Simpson, Dennis Sinclair, Garry Sinclair, Neil R Sinclair, Robert Sinclair, Sukhwinder Singh, Paul Siree, Richard Sisson, Matt Skanderup, Michael Skipper, Grace Skoczek, Shirley Skulmoski, Darrell Sleno, Doreen Smale, Lyle Small, David Smart, Bonnie Smith, Carl Smith, Catriona Smith, Glen Smith, Jennifer Smith, Lyle E Smith, Michael Smith, Michael Smith, Nancy Smith, Ryan Smith, Sandi Smith, Sandra Smith, Scott Smith, Tim K Smith, Tina Smith, Allen Smyl, Richard Smyl, Brad Smylie, Jeffrey Snide, Kurt Snow, William Snow, Douglas Snyder, Kristi Soderman, Lumbo Soma, Ray Soon, Curtis Sorochan, Daryl Soroko, Paul Spavor, Jason Spears, Kevin W Spencer, David Spetz, Evelien Spoelstra, David Spooner, Jill Spornitz, John Springer, Ellis Spurrell, Lawson Squire, Daniel D Srinivasagam, Eric St. Pierre, Robert St. Amant, Robert St. Martin, Mario St. Pierre, Carrie Stacey, Ian Stacey-Salmon, Stacey Stadnyk, Kendall Stagg, Rodney Stahn, Elisha Staines, Mark Stainthorpe, Karen Stairs, Randy Stamp, Nick Stanford, Lezlie Stark, Scott Stauffer, Scott Stauth, Achilles Stavropoulos, Craig Steel, Mark Steenbergen, Leanne Steeves, Jerry Stefanyshyn, Wayne Steffen, Robert Steinborn, Bradley Steinke, Carolyn Steinson, Taryn Stephenson, Jonathan Steranko, G Austin Stevens, Lyle Stevens, Robert Stevenson, Carol Stewart, Dana Stewart, Don Stewart, Douglas Stewart, Karen Stewart, Lorie Stewart, Wendy Stewart, Todd G Stiles, Kevin Stilwell, Stewart Stirling, Melissa Stockes, Anita Stockford, Katrina Stockman, Mark Stockton, Godfrey Stowe, Suzanne Strachan, Wade Strand, Linda Strangway, George Stratford, Brenda Stratichuk, William Strecker, Michael Street, William Stretch, Robert Struski, Linda Stuart, Mike Sturkenboom, David Sturrock, Stephen Suche, Mark Sullivan, Shiraz Sumar, Daniel Sutherland, Laura Sutherland, Scott Sverdahl, Rade Svorcan, Michael Swain, Rick Swanson, Halina Swierz, Don Sylvestre, Angela Szeponski, Darren Taciuk, David Talbot, Miguel Tamayo, Kevin Tanas, Valentina Taneva, J Nick Tannahill, Aaron Tannas, Krystalle Tanner, Michael Tanouye, Kari Tansowny, Boyd Tarasoff, Dan Tarasoff, Bill Tarkowski, Ron Taron, Darcy Tarrant, Ross Tarrant, Joanne Taubert, Raymond Taviner, Brian Taylor, Cathy Taylor, Colin Taylor, Dawn Taylor, George Taylor, Jackie Taylor, James Taylor, James R Taylor, Ken Taylor, Ken W Taylor, Thomas Taylor, Tom Taylor, William Taylor, Joseph Taza, Veniece Tedeschini, Chin Seng Teh, Berhanu Temesgen, Jennifer Temple, Robert Templeton, Derek Tempro, V Leighton Tenn, Kurt Tenney, Marilyn R Tenold, Travis Terpstra, Stephen Terry, Gus Teske, Jason Tessier, Cherie Thannhauser, Howard Thaw, Richard Theberge, Marc Theroux, Karen Thistleton, George Thomas, Laurie Thomas, Angela Thompson, Arthur cott Thompson, Ben Thompson, Herb Thompson, Mark Thompson, Peter Thomsen, Adele Thomson, Julie Thomson, Todd Thomson, Amber Thornton, Bruce Thornton, Keith Thornton, Richard William Thornton, Jason Thurlow, Margaret Thurmeier, Daniel Tillapaugh, Terry Tillotson, Colin Tiltman, Brian Timmerman, David Timms, Simon Timothy, Bruce E Tipton, Dharmendra Tiwary, Carol Tobin, Ron Tochor, James Todd, Mervin Todoschuk, Al Tokarchik, Christopher Tomlinson, Dale R Tomlinson, David Tonner, Domenic Torriero, Chyndelle Toth, David Toth, Paige Tracey, Sabrina D Traﬁ ak, Catherine Trenouth, Brian E Trimble, Ray Trombley, Ruaidhri Truter, Sunny Tulan, Brent Tulloch, Bruce Tumbach, Art Tupper, Terry Turgeon, Trent Turgeon, David Turk, Richard Turnbull, Donald Turner, Stanley Turner, Irene Tutto, Cary Twardy, David Tweddell, Wayne Tymchuk, Shaun Tymchyshyn, Kathleen Tynan, Kenechukwu Ufondu, Kevin Ullyott, Eric Ulrich, Gregory A Ulrich, Catherine Umpherville, Karl Unger, Stephen Unruh, Jackeline Urdaneta, Allan Valentine, Darrel Valin, Louis Vallee, Michael Vallee, Bryant VanIderstine, Christina VanderPyl, Vyvette Vanderputt, Collin Vare, Daniel Vasseur, Nicolette Vaughan, Sheila Verigin, Carmine Vertone, Nancy Tay Vetrici, Dale Vickery, Maria H Victoria Pereira, Wilf Vielguth, Tony Vitkunas, Demetry (Jim) Vlahos, James W Vollman, Leo Vollmin, Luke Vondermuhll, Nguyen Vu, Janel Wageman, Todd Waggoner, Trevor Wagil, Joy Wagner, Juon Wah, Donald Wakaruk, Ken Walchuck, Jeff Walden, Dave Waldner, David Walker, Martin Walker, Jeff Wall, Erin Wallace, Kevin Wallace, Marie Wallace, Andrew Wallis, Vince Wallwork, Lorie Walter, Michelle Walton, Roger Walton, Alfred Wandler, John A Wandler, Wanitta D Wandler, Blaise Wangler, Janet Wannop, Kathy Ward, Kirk Ward, Terry Ware, Wayne M J Warholik, Christopher Wark, Wanda Warman, John Warrell, Faye Warrington, Godfried Wasser, James Waterﬁ eld, Frank Watkin, Julie Watkins, Kenneth Watson, Trish Wear, Alan Webb, Byron Webb, Larry Webb, Randall Weeks, Maureen C Weeres, Lionel Weinrauch, Randy Weir, Gregory Wells, Guy Welwood, Mark S Wenner, Dwayne Werle, Tracy Wersch, Craig Werstiuk, Matthew Werstiuk, Darrin West, Jacqueline West, Jeremy Wetsch, Terry Wetzstein, John Wham, Terence Whang, Loyd Wheating, Joshua Wheaton, Andrew Wheeler, Bob W Wheeler, Francis W White, Gail White, Julie White, Ken White, Ralph White, David Whitehouse, John Whitlock, Grant Whittemore, Michael Whittingham, Heather Whynot, Jane Whyte, Blaine Wicentovich, David Wiebe, Debbie Wiens, Cameron Wietzel, Cheryl Wiggett, Zandra Wigglesworth, Bob Wilbern, Brandon Wild, John Wilding, Daryl Wiles, Troy Wilk, Melanie Wilkie, Amy Wilkinson, Derek Wilkinson, Elmer Willard, Shannon Willcott, Bill Williams, Grant Williams, Greg Williams, Julian Williams, Kelvin Williamson, Monty Williamson, Jeff Willick, Kennneth Willis, Robin Willis, Wayne Willis, Susan Wills, Christian Willson, Curtis Wilson, Don Wilson, Ian Wilson, James Wilson, Jeff Wilson, Marty Wilson, Patrick Wilson, Tammy Wilson, Tyler Wilson, Woodrow Wilson, Joan Wilton, Bob Wing, Ken Winsborrow, Noel Winter, Greg Winters, Garrett Wirachowsky, Jeff Wiseman, Morrison Wiseman, Paul Wiseman, Dale Wittman, Kelly Woidak, Colin Woloshyn, C K Bill Wong, Jason Wong, Jennifer Wong, Lisa Wong, Steve Wong, E Bette Wood, Leonard Wood, Philip Wood, Roxanne Wood, Laura Wooding, Travis Woods, Marilyn Woodske, Wayne Woodward, Sidney Wosnack, Raymond Wourms, Mark Woynarowich, Chris Wright, Daniel Wright, Richard Wright, Bin Wu, Christine Wutzke, Brent Wychopen, Guy Wylie, George Wyndham, Brent Wyness, Barry Wynne, Valerie Wyonzek, Cameron Yamada, Canghu Yang, Grace Yang, Lin Yang, Andrew Yaremko, Rick Yarmuch, James Yaroslawsky, Jeff Yates, Noah Yates, Betty Yee, Davin Yee, Gordon Yee, Michael Yee, WSelina Yeung, Jeffrey Yip, Kitty Yip, Darrell York, Rachelle Yorke, Daryl Youck, Bill Young, Chalene Young, Clayton Young, Kelly Young, Richard Young, Wendell Young, Ray Yowney, Clement Yuen, Dustin Yuill, Jeff Yuill, William Yuill, Arina Yuzhakova, Robin Zabek, Robert Zabot, Gabriel Zachoda, Tyler Zachoda, Cam Zackowski, John E Zahary, Attila Zahorszky, Mark Zan, Glenn Zeebregts, Patricia Zegers-de-Beyl, Lynn Zeidler, Tony Zeiser, Aleksandra Zelic, Diane Zeliznik, Grant Zellweger, Darcy Zelman, Denis Zentner, Kathy Zerr, Michelle Zerr, Xu (Frank) Zhang, Wanli Zhu, Evgeny Zhuromsky, Brenda Ziegler, Dwayne Zilinski, Hernando Zorrilla, Ana Zulueta, Bob Zulueta. The People 13 The Plan We have a strong track record of setting a plan and diligently delivering against it. That being said, we remain ﬂ exible to react to market changes or take advantages of opportunities as they arise. Review of Operations PRODUCTION STRATEGY AND RESULTS Canadian Natural has increased its hydrocarbon production and reserves each and every year since becoming an independent producer in 1989. Throughout that 17 year period we have adhered to the same basic business formula - maintain large project inventories in every product and basin in which we participate. Large project inventories enable the Company to continually high-grade the capital allocation process and balance production mix among each of the commodities we produce; namely natural gas, light crude oil, Pelican Lake crude oil, primary heavy crude oil and thermal heavy crude oil. In 2005 we again achieved record levels of production on a barrel of oil equivalent basis. Production before royalties on a barrel of crude oil equivalent was 553 mboe/d during 2005, up 8% from 2004 levels and was achieved primarily through a combination of exploration and asset development. Natural gas production before royalties increased by 4% and continues to represent our largest product offering. Total crude oil and NGLs production before royalties increased by 11%, with the primary drivers being the commencement of production from the Baobab Field located offshore Côte d’Ivoire and improvements in production from North Sea light crude oil, Pelican Lake crude oil and the Primrose in-situ oil sands development. (before royalties) Natural gas North America light crude oil and NGLs Pelican Lake crude oil Primary heavy crude oil Thermal heavy crude oil North Sea light crude oil Offshore West Africa light crude oil Total 2005 2004 Production mboe/d Mix % Production mboe/d 240 52 23 93 53 69 23 553 43 10 4 17 10 12 4 100 231 47 20 95 44 65 12 514 Mix % 45 9 4 19 8 13 2 100 (cid:12)(cid:62)(cid:136)(cid:143)(cid:222)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195) (cid:173)(cid:147)(cid:147)(cid:86)(cid:118)(cid:201)(cid:96)(cid:174) (cid:12)(cid:62)(cid:136)(cid:143)(cid:222)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:62)(cid:152)(cid:96)(cid:202)(cid:32)(cid:20)(cid:29)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195) (cid:173)(cid:147)(cid:76)(cid:76)(cid:143)(cid:201)(cid:96)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:93)(cid:123)(cid:206)(cid:153) (cid:163)(cid:93)(cid:206)(cid:110)(cid:110) (cid:163)(cid:93)(cid:211)(cid:153)(cid:153) (cid:163)(cid:93)(cid:211)(cid:206)(cid:211) (cid:153)(cid:163)(cid:110) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:206)(cid:163)(cid:206) (cid:211)(cid:110)(cid:206) (cid:211)(cid:123)(cid:211) (cid:211)(cid:163)(cid:120) (cid:211)(cid:228)(cid:200) 14 The Plan: Review of Operations THE PEOPLE Our technical skills are strong and our people are motivated. THE PLAN Our exploitation approach is ﬂ exible to accomodate changes in our operating environment. THE ASSETS We have exposure to many play types, through ownership of one of the largest landholding positions in the WCSB. Africa saw the acquisition of 2,400 kilometers of proprietary 2-D seismic data and the purchase and reprocessing of 1,530 square kilometers of 3-D seismic data. STRATEGIC LAND BASE Canadian Natural has the second largest undeveloped land inventory in the WCSB. At the end of 2005, our Canadian undeveloped net acreage totaled 10.9 million net acres. Total landholdings were 16.6 million net acres at the end of 2005, up slightly from 2004. land base affords strong concentrated signiﬁ cant This opportunities to maintain our low ﬁ nding and onstream costs and low operating costs. The vast majority of our land base is positioned to utilize existing owned and operated infrastructure and it also strategically positions us to maximize the beneﬁ t of new play types developed by ourselves and other producers adjacent to our core operating areas. We can also lever newly discovered opportunities into upside potential for our existing lands or into acquisition of competitor lands. As an example, in late 2003, we leveraged our vast Northeast British Columbia land base to correlated well data to develop a new regional shallow natural gas play. In 2005, production from this shallow play reached 35 mmcf/d. TIM S. McKAY Senior Vice-President, North American Operations MARY-JO E. CASE Vice-President, Land GEO-SCIENCE STRATEGY We believe that a disciplined focus on geology and geophysics reduces exploration risk and ultimately results in better full cycle economics. We drill hundreds of wells each year and add new high quality locations to our inventory by integrating geological plays with seismic data analysis. The achievements of our experienced team of geologists and geophysicists is reﬂ ected in our quality results. Canadian Natural continues to be active in adding quality locations to its inventory by integrating geological plays with seismic data analysis. In Canada, we invested $96 million during 2005 to acquire new seismic and to purchase and reprocess existing seismic data. In total, over 4,389 kilometers of conventional 2-D seismic data and over 430 square kilometers of 3-D seismic data were acquired. Additionally, over 12,577 kilometers of conventional 2-D seismic data and 986 square kilometers of 3-D seismic data were purchased. We continue to acquire this data under stringent environmental controls and in a cost effective manner. In the North Sea, we purchased 2,800 square kilometers of 2-D seismic and reprocessed a further 64 square kilometers of 3-D seismic data. This data allows us to continue aggressive in-ﬁ eld and near-ﬁ eld development and exploration. Offshore West (cid:45)(cid:105)(cid:136)(cid:195)(cid:147)(cid:136)(cid:86)(cid:202)(cid:105)(cid:221)(cid:171)(cid:105)(cid:152)(cid:96)(cid:136)(cid:204)(cid:213)(cid:192)(cid:105)(cid:195)(cid:202)(cid:136)(cid:152)(cid:202)(cid:10)(cid:62)(cid:152)(cid:62)(cid:96)(cid:62) (cid:173)(cid:102)(cid:202)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:195)(cid:174) (cid:47)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:32)(cid:156)(cid:192)(cid:204)(cid:133)(cid:202)(cid:1)(cid:147)(cid:105)(cid:192)(cid:136)(cid:86)(cid:62)(cid:152)(cid:202)(cid:143)(cid:62)(cid:152)(cid:96)(cid:133)(cid:156)(cid:143)(cid:96)(cid:136)(cid:152)(cid:125)(cid:195) (cid:173)(cid:204)(cid:133)(cid:156)(cid:213)(cid:195)(cid:62)(cid:152)(cid:96)(cid:195)(cid:202)(cid:156)(cid:118)(cid:202)(cid:152)(cid:105)(cid:204)(cid:202)(cid:62)(cid:86)(cid:192)(cid:105)(cid:195)(cid:174) (cid:12)(cid:105)(cid:219)(cid:105)(cid:143)(cid:156)(cid:171)(cid:105)(cid:96) (cid:49)(cid:152)(cid:96)(cid:105)(cid:219)(cid:105)(cid:143)(cid:156)(cid:171)(cid:105)(cid:96) (cid:153)(cid:200) (cid:200)(cid:163) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:123)(cid:228) (cid:123)(cid:110) (cid:123)(cid:200) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:120)(cid:93)(cid:200)(cid:153)(cid:153) (cid:123)(cid:93)(cid:110)(cid:110)(cid:153) (cid:123)(cid:93)(cid:228)(cid:206)(cid:200) (cid:206)(cid:93)(cid:110)(cid:206)(cid:211) (cid:206)(cid:93)(cid:120)(cid:199)(cid:110) (cid:200)(cid:93)(cid:211)(cid:199)(cid:211) (cid:163)(cid:228)(cid:93)(cid:153)(cid:123)(cid:199) (cid:163)(cid:163)(cid:93)(cid:120)(cid:211)(cid:206) (cid:153)(cid:93)(cid:110)(cid:163)(cid:163) (cid:163)(cid:228)(cid:93)(cid:211)(cid:163)(cid:206) The Plan: Review of Operations 15 The infrastructure associated with this vast, concentrated land base also provides a competitive advantage in terms of lower marginal operating and development costs for newly drilled or acquired properties. This dominance can create property acquisition opportunities, as we maintain a low-cost regime and access to infrastructure. Internationally, our North Sea net undeveloped acreage remained strong while Offshore West Africa net undeveloped lands decreased following the sale of leases held in Angola as partially offset by the acquisition of lands in Gabon. CORE LANDHOLDINGS The Company’s overall average landholding working interest of 82% reﬂ ects the Company’s philosophy to maintain high ownership levels and control operations. Assets are better developed and exploited according to the Company’s own plans and timelines. This ﬂ exibility allows the Company to maintain discipline in its capital expenditures. For example, in 2004 as a result of capital allocated to strategic property acquisitions, the Company inventoried many of its planned 2004 drilling locations for future years. (thousands of acres) North America Developed Undeveloped North Sea Developed Undeveloped Offshore West Africa Developed Undeveloped Total Developed Undeveloped Gross 7,184 13,163 20,347 138 457 7 521 7,329 14,141 21,470 2005 Net 5,699 10,947 16,646 93 352 4 426 5,796 11,725 17,521 % 79 83 82 67 77 58 82 79 83 82 Gross 6,577 14,051 20,628 138 830 8 1,672 6,723 16,553 23,276 2004 Net 4,889 11,523 16,412 93 565 5 886 4,987 12,974 17,961 % 74 82 80 67 68 59 53 74 78 77 extensive prospect inventory, it would have been a challenge to complete the majority of the program in an economic and disciplined manner. The merits of this discipline and planning are reﬂ ected in our ﬁ nding and onstream cost control. DRILLING ACTIVITY AND STRATEGY During 2005, we completed the largest drilling program in the Company’s history, a total of 1,882 wells or 30% more than in 2004. Our drilling success rate of 93% improved slightly over the prior year and reﬂ ects the low-risk exploitation approach that we take to the business. In 2005 our drilling plans were the most comprehensive we have ever prepared in Canada, including an organized migration of rigs to optimize utilization and better balance drilling activities throughout the year. We leveraged that plan and our extensive drilling inventory to its fullest extent due to weather. Warmer than normal winter weather in 2005 led to an earlier spring breakup for winter access areas and a much wetter than normal summer was followed by a late freeze up for the 2005/6 winter drilling season. This meant that our execution had to be ﬂ exible and had we not developed such a comprehensive plan with an (cid:47)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:152)(cid:105)(cid:204)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96) (cid:12)(cid:192)(cid:136)(cid:143)(cid:143)(cid:136)(cid:152)(cid:125)(cid:202)(cid:195)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:202)(cid:192)(cid:62)(cid:204)(cid:105)(cid:93) (cid:105)(cid:221)(cid:86)(cid:143)(cid:213)(cid:96)(cid:136)(cid:152)(cid:125)(cid:202)(cid:195)(cid:204)(cid:192)(cid:62)(cid:204)(cid:136)(cid:125)(cid:192)(cid:62)(cid:171)(cid:133)(cid:136)(cid:86)(cid:202)(cid:204)(cid:105)(cid:195)(cid:204)(cid:201)(cid:195)(cid:105)(cid:192)(cid:219)(cid:136)(cid:86)(cid:105)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195) (cid:173)(cid:175)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:93)(cid:123)(cid:123)(cid:153) (cid:163)(cid:93)(cid:110)(cid:110)(cid:211) (cid:163)(cid:93)(cid:199)(cid:153)(cid:206) (cid:153)(cid:228)(cid:228) (cid:163)(cid:93)(cid:228)(cid:153)(cid:211) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) 16 The Plan: Review of Operations (cid:153)(cid:206) (cid:153)(cid:163) (cid:153)(cid:163) (cid:153)(cid:123) (cid:153)(cid:200) For 2006 we plan to take our comprehensive drilling plans one step further and design the drilling program to optimize the capabilities of the drill rig contracted for the area. That is, while some rigs may be capable of a wide range of applications, there is generally a range of depths in which the rig is at its optimum efﬁ ciency. We will target wells that have depths or other requirements that ﬁ t within these optimum efﬁ ciencies. This will help ensure that every dollar spent is generating maximum value. Those wells in inventory that do not ﬁ t into the criteria for the drill rig in 2006 will be re-inventoried for drilling in a future year when the most efﬁ cient rig type is available in that area. Year Ended December 31 Crude oil North America Light oil Pelican Lake Primary heavy oil Thermal heavy oil North Sea Offshore West Africa Natural gas – North America Northeast British Columbia Northwest Alberta Northern Plains Southern Plains Dry Subtotal Stratigraphic test / service wells Total 2005 2004 Gross Net Success Net Success 107 83 369 107 13 6 685 230 184 240 417 1,071 136 1,892 251 2,143 81 83 341 107 12 3 627 201 152 199 338 890 117 1,634 248 1,882 92% 99% 94% 98% 87% 85% 95% 88% 92% 84% 99% 91% 93% 97% 100% 96% 100% 82% 77% 97% 89% 92% 80% 95% 89% 91% 45 34 180 58 9 2 328 167 138 163 221 689 96 1,113 336 1,449 North American crude oil drilling increased substantially from 2004 levels when capital was reallocated following four major property acquisitions. The largest increase in drilling occurred on primary heavy crude oil projects where activity was ramped by over 90%. This was reﬂ ected in associated production volumes which increased from approximately 92 mbbl/d in the ﬁ rst quarter to over 96 mbbl/d in the fourth quarter. Drilling at Pelican Lake increased by 50 net wells or 147% due to increased activity associated with enhanced oil recovery schemes and additional primary production potential that continues to expand our developable land base. Associated production at Pelican Lake increased from approximately 18 mbbl/d in the ﬁ rst quarter to over 28 mbbl/d in the fourth quarter. Thermal drilling activity increased 90% reﬂ ecting the development of the North Primrose Field which commenced production in early 2006. ACTIVITY BY CORE REGION Natural gas drilling activity also increased in each of our core regions and by 26% overall when compared with 2004 levels. Drilling in Northeast British Columbia increased with 26% more wells being drilled across a variety of depths and geological structures. In Northwest Alberta, 76 net Cardium wells were drilled versus 69 in 2004. In the Plains increased activity was associated with coal bed methane gas with 100 net wells drilled and shallow gas with 209 net wells drilled. During the year, 126 net stratigraphic wells were drilled on our oil sands mining leases and 95 were drilled on our conventional leases to delineate resource potential. A total of 27 net service wells were drilled including 25 wells in North America and 2 wells internationally. Northeast British Columbia Northwest Alberta Northern Plains Southern Plains Southeast Saskatchewan Horizon Oil Sands Project United Kingdom North Sea Offshore West Africa Net Undeveloped Land (thousands of net acres) 2004 2005 2,027 1,507 6,594 621 82 116 352 426 11,725 2,040 1,660 6,922 661 123 116 565 886 12,974 Drilling Activity (net wells) 2005 241 183 907 354 52 126 14 5 1,882 2004 192 156 613 240 13 218 14 3 1,449 The Plan: Review of Operations 17 THE PEOPLE Our people understand our customers and have creatively found ways to expand the markets we sell to. THE PLAN We seek to maximize market potential for every product we sell. In particular, we leverage our 3-Phase heavy crude oil marketing plan to access our vast resource base. THE ASSETS Our midstream infrastructure provides us with ﬂ exibility. The ECHO pipeline delivers undiluted raw bitumen used in our Synbit and WCS crude oil blends. Marketing NATURAL GAS Canadian Natural’s gas marketing objective is to maximize the realized price for its overall portfolio. Our strategy requires us to develop solid business relationships based on demonstrated performance and integrity and to work together with our customers to meet their needs. The Company markets primarily to large credit worthy utilities, industrial and commercial customers across North America. The current portfolio includes 20% of direct sales to various American customers, 69% sold directly into our domestic markets with the remaining 11% going to the Alberta based gas supply and market aggregators. Canadian Natural’s portfolio is essentially driven by current market prices with over 98% of all sales ﬂ uctuating with the pricing index prevailing at the points of physical delivery of the gas. The marketing team monitors regulatory applications by the pipeline companies and participates as necessary to ensure an optimal outcome is achieved for all concerned parties. Canadian Natural’s realized wellhead price improved by 32% in 2005 to $8.57/mcf primarily in response to a very tight North American supply environment exacerbated by the devastating hurricanes Katrina and Rita impacting the US Gulf Coast in early Fall of 2005. The average annual prices for 2005 were up 41% on the NYMEX and 25% at the AECO hub with the basis differential at AECO widening by 63% in Canadian dollars over the 2004 average. As of early March 2006, the cumulative losses of gas production from the affected areas are estimated at 678 bcf with some 1.4 bcf/d of production still down. This extraordinary supply disruption resulted in very high gas prices reaching US$15/mmbtu in December 2005 and causing several industrial plants to curtail or temporarily shutdown their operations. However, this winter will also be characterized by the warmest 18 The Plan: Marketing month of January on record creating a very volatile pricing environment with the current NYMEX price at the US$7/ mmbtu level. The gas storage positions are expected to close the withdrawal season at the end of March 2006 at levels not seen since 1991. The drilling activity continued to be very high in 2005 with a record number of completions in Canada at 16,700 and the US at 27,000. However, the North American overall supply was essentially ﬂ at year over year with the increase in the electrical generation offset by the losses from the industrial sector. We expect the North American supplies to be challenged over the next several years even with the increased drilling for the tight gas in the Rockies and the promising CBM in Alberta. The timeframe for the production of gas from the McKenzie Delta and Alaska projects continue to be extended into the next decade given the economic and regulatory challenges. The large number of proposals to import liqueﬁ ed natural gas in the North American grid has yet to translate into incremental quantities available to the end users with the 2005 import volumes remaining ﬂ at at 1.8 bcf/d. The forecast is for a modest increase of these volumes in 2006 as the competition for supplies intensiﬁ es with European and Asian markets. (cid:32)(cid:57)(cid:31)(cid:13)(cid:56)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:192)(cid:105)(cid:118)(cid:105)(cid:192)(cid:105)(cid:152)(cid:86)(cid:105)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:136)(cid:152)(cid:125) (cid:173)(cid:49)(cid:45)(cid:102)(cid:201)(cid:147)(cid:147)(cid:76)(cid:204)(cid:213)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:110)(cid:176)(cid:120)(cid:200) (cid:200)(cid:176)(cid:228)(cid:153) (cid:120)(cid:176)(cid:123)(cid:123) (cid:206)(cid:176)(cid:211)(cid:120) (cid:123)(cid:176)(cid:206)(cid:110) The marketing team maximizes our wellhead price realizations by optimizing the logistics and creatively developing new markets for our heavy crude oil. RÉAL M. CUSSON Senior Vice-President, Marketing Canadian Natural’s natural gas production for 2006 is forecast to average between 1,450 – 1,515 mmcf/d and with the current 2006 pricing strips for NYMEX at US$7.95/mmbtu and AECO at C$7.22/GJ this would yield an overall wellhead price of C$7.12/mcf for our sales portfolio, using a US$0.88/C$1.00 exchange rate. The benchmark price for WTI crude oil was up 37% in 2005 US$56.61/bbl and the Brent crude oil was higher than in 2004 by 42% to US$54.45/bbl. The price differential for the Lloyd Blend heavy crude oil widened by a signiﬁ cant 5% in 2005 to an average of 37% of the WTI price and the Canadian currency strengthened by 7% over the US dollar. CRUDE OIL Canadian Natural’s crude oil marketing strategy is designed to unlock the value of our vast heavy oil reserves. The three major components of our strategy consist of blending various crude oil streams and diluents to better serve the needs of our reﬁ ning customers, support and participate in the expansion of pipeline export capacity and to support and participate in projects adding incremental conversion capacity for bitumen and SCO. Canadian Natural’s realized wellhead price improved by 23% in 2005 to $46.86/bbl mainly based on the strong worldwide demand for hydrocarbons and a constrained supply environment with practically no spare capacity from the producers and full utilization of worldwide reﬁ ning assets. The demand continues to grow strongly in the Asian markets and moderately in the North American and European markets while the supplies are essentially at capacity. The worldwide reserves are generally abundant, however there are several economic, logistical, labour related, and geopolitical challenges to overcome to bring on additional production on a sustainable basis. The damage caused by the hurricanes in the US Gulf Coast and the operational problems encountered at several reﬁ neries in 2005 simply exacerbated an already tight balance for hydrocarbon products. (cid:55)(cid:47)(cid:22)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:192)(cid:105)(cid:118)(cid:105)(cid:192)(cid:105)(cid:152)(cid:86)(cid:105)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:136)(cid:152)(cid:125) (cid:173)(cid:49)(cid:45)(cid:102)(cid:201)(cid:76)(cid:76)(cid:143)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:206)(cid:163)(cid:176)(cid:228)(cid:211) (cid:211)(cid:200)(cid:176)(cid:163)(cid:163) (cid:211)(cid:120)(cid:176)(cid:153)(cid:163) (cid:120)(cid:200)(cid:176)(cid:200)(cid:163) (cid:123)(cid:163)(cid:176)(cid:123)(cid:206) The Plan: Marketing 19 (cid:29)(cid:143)(cid:156)(cid:222)(cid:96)(cid:202)(cid:76)(cid:143)(cid:105)(cid:152)(cid:96)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:105)(cid:202)(cid:96)(cid:136)(cid:118)(cid:118)(cid:105)(cid:192)(cid:105)(cid:152)(cid:204)(cid:136)(cid:62)(cid:143)(cid:202)(cid:204)(cid:156)(cid:202)(cid:55)(cid:47)(cid:22) (cid:173)(cid:175)(cid:174) (cid:31)(cid:62)(cid:222)(cid:62)(cid:202)(cid:135)(cid:202)(cid:29)(cid:29)(cid:9)(cid:202)(cid:195)(cid:171)(cid:192)(cid:105)(cid:62)(cid:96) (cid:173)(cid:49)(cid:45)(cid:102)(cid:201)(cid:76)(cid:76)(cid:143)(cid:174) (cid:211)(cid:228)(cid:176)(cid:228)(cid:228) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:206)(cid:199) (cid:206)(cid:211) (cid:211)(cid:110) (cid:211)(cid:120) (cid:123)(cid:163) (cid:163)(cid:120)(cid:176)(cid:228)(cid:228) (cid:163)(cid:228)(cid:176)(cid:228)(cid:228) (cid:120)(cid:176)(cid:228)(cid:228) (cid:228) (cid:173)(cid:120)(cid:176)(cid:228)(cid:228)(cid:174) (cid:27)(cid:62)(cid:152)(cid:135)(cid:228)(cid:206) (cid:27)(cid:213)(cid:143)(cid:135)(cid:228)(cid:206) (cid:27)(cid:62)(cid:152)(cid:135)(cid:228)(cid:123) (cid:27)(cid:213)(cid:143)(cid:135)(cid:228)(cid:123) (cid:27)(cid:62)(cid:152)(cid:135)(cid:228)(cid:120) (cid:27)(cid:213)(cid:143)(cid:135)(cid:228)(cid:120) (cid:27)(cid:62)(cid:152)(cid:135)(cid:228)(cid:200) Canadian Natural continued to successfully implement its blending strategy in 2005 by contributing 55% of the total 255 mbbl/d of WCS stream in the fourth quarter. To further enhance our blending ﬂ exibility and economics, we have initiated a full evaluation for the importation of condensate or natural gasoline from various American facilities. The logistical challenges are being addressed by industry and signiﬁ cant progress was achieved in 2005 with the approval of the Enbridge Southern Access Pipeline expansion which will add 394 mbbl/d to the greater Chicago market area by 2009 and the Terasen TMX 1 project to add a total of 75 mbbl/d to the West Coast by 2008. The TCPL Keystone project to add 400 mbbl/d to the Woodriver market area with further option to extend to Cushing has received sufﬁ cient commitments to proceed further. Two long haul pipeline projects are being developed to transport oil from Edmonton to the West Coast with access to the US reﬁ neries and the Asian markets. The Enbridge Gateway project is for 400 mbbl/d to Kitimat and the Terasen TMX project is for 625 mbbl/d split between Vancouver and Kitimat/Prince Rupert. We believe these two projects are at least ﬁ ve years away given the required market developments and regulatory requirements. We are conﬁ dent that the industry will proceed with the necessary incremental pipeline export capacity on a timely basis to support the expected incremental production out of the WCSB and speciﬁ cally from the oil sands projects. The Corsicana pipeline is scheduled to ship heavy crude oil from Patoka, IL to Nederland, TX by late March 2006. Canadian Natural has committed 25 mbbl/d for ﬁ ve years on this pipeline that could eventually carry up to 80 mbbl/d to US Gulf Coast reﬁ neries. The Spearhead pipeline started shipping 80 mbbl/d of oil from Chicago, IL to Cushing, OK on March 2, 2006 and has the capacity to ship 125 mbbl/d. Both pipelines could be expanded further with market demands for Canadian crude oil. Canadian Natural continues to work with North American reﬁ ners to encourage them to add more conversion capacity to their facilities. The Company is also proceeding with a full evaluation of its second heavy crude oil upgrading facilities in addition to its Horizon Project. The full scope deﬁ nition and the detailed evaluation of the upgrading technology to be used are currently underway at the selected engineering ﬁ rms and we expect to complete this phase in early 2007. We intend to follow the same rigorous process employed for the Horizon Project. The initial concept is to upgrade the bitumen into a sweet SCO and to incorporate the synergistic beneﬁ ts of heat integration between the upgrading process and the thermal bitumen production with the potential use of the gasiﬁ cation technology. Canadian Natural’s portfolio for 2006 is forecast to average between 335 mbbl/d and 373 mbbl/d and with the current 2006 pricing strips for WTI at US$64.42/bbl would yield an overall wellhead price of C$37.73/bbl, using a US$0.88/C$1.00 exchange rate. PRICE RISK MANAGEMENT Canadian Natural utilizes hedging techniques to provide some assurance on price realizations and to protect cash ﬂ ow generation capability in order to fund ongoing development programs. Generally, the downside pricing risks associated with various commodities are determined and, if deemed appropriate, ﬁ nancial derivatives are used to limit risk. Currency exposures are also monitored and may be hedged in conjunction with commodities. 20 The Plan: Marketing In conjunction with approval of the Horizon Project, our Board of Directors granted management the authority to hedge up to 75% of any commodity’s expected production volumes for a forward 12-month period, up to 50% of the second 12-month period and up to 25% for the following 24-month period. MIDSTREAM Our midstream assets consist of the 100% owned and operated Echo pipeline, the 15% interest in the Cold Lake Pipeline system, the 62% interest in the operated Pelican Lake Pipeline and the 50% interest in the 84 megawatt co-generation unit located at our Primrose facility. The midstream assets allow us to control and optimize transportation costs for about 80% of our heavy crude oil production and generate additional revenues from third party volumes and the sale of surplus electricity. Echo is the only pipeline delivering undiluted raw bitumen to the Hardisty terminals and plays an important role in our heavy crude oil blending and marketing strategy for WCS and other diluted bitumen blends. We will be completing a lateral pipeline from its ECHO pipeline to our Morgan battery in the third quarter of 2006 at a cost of $6 million to increase the utilization rate from 86% in 2005 to 90% once completed. The 2005 revenues from our Midstream assets increased by 16.6% to $77 million primarily from higher volumes on Echo and Pelican pipelines, increased revenues from our Nipisi terminal and higher sales of surplus electricity from our Primrose cogeneration facility into the Alberta provincial grid. (cid:10)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:202)(cid:62)(cid:219)(cid:105)(cid:192)(cid:62)(cid:125)(cid:105)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:195)(cid:105)(cid:143)(cid:143)(cid:136)(cid:152)(cid:125)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:105) (cid:173)(cid:10)(cid:102)(cid:201)(cid:147)(cid:86)(cid:118)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:211) (cid:110)(cid:176)(cid:120)(cid:199) (cid:200)(cid:176)(cid:120)(cid:228) (cid:200)(cid:176)(cid:211)(cid:163) (cid:206)(cid:176)(cid:199)(cid:199) (cid:120)(cid:176)(cid:123)(cid:120) (cid:10)(cid:156)(cid:147)(cid:171)(cid:62)(cid:152)(cid:222)(cid:202)(cid:62)(cid:219)(cid:105)(cid:192)(cid:62)(cid:125)(cid:105)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:62)(cid:152)(cid:96)(cid:202)(cid:32)(cid:20)(cid:29)(cid:195)(cid:202)(cid:195)(cid:105)(cid:143)(cid:143)(cid:136)(cid:152)(cid:125)(cid:202)(cid:171)(cid:192)(cid:136)(cid:86)(cid:105) (cid:173)(cid:10)(cid:102)(cid:201)(cid:76)(cid:76)(cid:143)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:123)(cid:200)(cid:176)(cid:110)(cid:200) (cid:206)(cid:199)(cid:176)(cid:153)(cid:153) (cid:206)(cid:211)(cid:176)(cid:200)(cid:200) (cid:206)(cid:163)(cid:176)(cid:211)(cid:211) (cid:211)(cid:206)(cid:176)(cid:123)(cid:120) (cid:10)(cid:62)(cid:152)(cid:62)(cid:96)(cid:62)(cid:201)(cid:49)(cid:45)(cid:202)(cid:62)(cid:219)(cid:105)(cid:192)(cid:62)(cid:125)(cid:105)(cid:202)(cid:105)(cid:221)(cid:86)(cid:133)(cid:62)(cid:152)(cid:125)(cid:105)(cid:202)(cid:192)(cid:62)(cid:204)(cid:105) (cid:173)(cid:49)(cid:45)(cid:102)(cid:202)(cid:136)(cid:152)(cid:202)(cid:105)(cid:181)(cid:213)(cid:136)(cid:219)(cid:62)(cid:143)(cid:105)(cid:152)(cid:204)(cid:202)(cid:10)(cid:102)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:176)(cid:211)(cid:163) (cid:163)(cid:176)(cid:206)(cid:228) (cid:163)(cid:176)(cid:123)(cid:228) (cid:163)(cid:176)(cid:120)(cid:199) (cid:163)(cid:176)(cid:120)(cid:120) The Plan: Marketing 21 THE PEOPLE Capital discipline is ingrained throughout all operating units. They are accountable for the capital they spend and the value they create. THE PLAN Maintain good access to capital markets while ensuring balance in our borrowing sources and the term of their maturities. THE ASSETS Backstopping our ﬁ nances are assets capable of generating signiﬁ cant free cash ﬂ ow, even in a lower priced environment. Financial Plan Canadian Natural has always viewed ﬁ nancial strength as integral to ongoing success. We have carefully developed our ﬁ nancial capacity to both proﬁ tably grow our conventional crude oil and natural gas business and to ﬁ nance this growth as well as construction of our world class Horizon Oil Sands Project. OUR FINANCIAL STRENGTHS ARE MANY AND INCLUDE: • A diverse asset base both geographically and by product, most of which is located in G-7 countries with stable and secure economies. This, coupled with our exploitation approach to the business, reduces operational risk. • Financial liquidity, including $3.4 billion of bank credit facilities, $3.3 billion of which were unutilized at December 31, 2005. In concert with the sanctioning of the Horizon Project and as more fully described in the Management’s Discussion and Analysis, our risk management program was increased during 2005. In order to avoid ﬁ nancial stress should commodity prices fall during the period of 2005 through 2008 when we are constructing Phase 1 of the project, the increased assurance of future cash ﬂ ow levels afforded by the risk management program, combined with the high degree of cost certainty acquired for construction costs, were critical to the sanctioning of Phase 1 of the Horizon Project. As a strong investment grade borrower, we have many ﬁ nancial ratios to which we steward. For example, we target to maintain a debt to book capitalization of about 35% to 45%, depending upon where we are in the business cycle. Assuming a post 2006 US$35/bbl WTI price environment, we believe that our disciplined approach to balance sheet management will facilitate • A diversiﬁ ed production base with strong internally generated cash ﬂ ows, supported by a proactive hedge program. • Flexible capital expenditures program with a balance of solid production maintenance as well as short-, medium-, and long-term initiatives. • A proactive, ﬂ exible approach to project development and ﬁ nancing strategies predicated upon our 5- and 10- year business plans. • A strong balance sheet with a debt to book capitalization of 29% as at December 31, 2005. (cid:12)(cid:105)(cid:76)(cid:204)(cid:202)(cid:204)(cid:156)(cid:202)(cid:76)(cid:156)(cid:156)(cid:142)(cid:202)(cid:86)(cid:62)(cid:171)(cid:136)(cid:204)(cid:62)(cid:143)(cid:136)(cid:226)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152) (cid:173)(cid:175)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:211)(cid:110)(cid:176)(cid:199) (cid:206)(cid:206)(cid:176)(cid:110) (cid:206)(cid:211)(cid:176)(cid:110) (cid:123)(cid:199)(cid:176)(cid:163) (cid:123)(cid:163)(cid:176)(cid:199) 22 The Plan: Financial Plan DOUGLAS A. PROLL Chief Financial Ofﬁ cer & Senior Vice-President, Finance RANDALL S. DAVIS Vice-President, Financial Accounting & Controls (cid:45)(cid:86)(cid:133)(cid:105)(cid:96)(cid:213)(cid:143)(cid:105)(cid:96)(cid:202)(cid:96)(cid:105)(cid:76)(cid:204)(cid:202)(cid:192)(cid:105)(cid:171)(cid:62)(cid:222)(cid:147)(cid:105)(cid:152)(cid:204)(cid:195) (cid:173)(cid:10)(cid:102)(cid:202)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:195)(cid:174) (cid:10)(cid:62)(cid:152)(cid:62)(cid:96)(cid:136)(cid:62)(cid:152)(cid:202)(cid:31)(cid:47)(cid:32)(cid:195) (cid:49)(cid:45)(cid:202)(cid:32)(cid:156)(cid:204)(cid:105)(cid:195) (cid:42)(cid:192)(cid:136)(cid:219)(cid:62)(cid:204)(cid:105)(cid:202)(cid:42)(cid:143)(cid:62)(cid:86)(cid:105)(cid:147)(cid:105)(cid:152)(cid:204)(cid:195)(cid:202) (cid:120)(cid:228)(cid:228) (cid:123)(cid:228)(cid:228) (cid:206)(cid:228)(cid:228) (cid:211)(cid:228)(cid:228) (cid:163)(cid:228)(cid:228) (cid:228) (cid:200) (cid:228) (cid:228) (cid:211) (cid:199) (cid:228) (cid:228) (cid:211) (cid:110) (cid:228) (cid:228) (cid:211) (cid:153) (cid:228) (cid:228) (cid:211) (cid:228) (cid:163) (cid:228) (cid:211) (cid:163) (cid:163) (cid:228) (cid:211) (cid:211) (cid:163) (cid:228) (cid:211) (cid:206) (cid:163) (cid:228) (cid:211) (cid:123) (cid:163) (cid:228) (cid:211) (cid:120) (cid:163) (cid:228) (cid:211) (cid:200) (cid:163) (cid:228) (cid:211) (cid:199) (cid:163) (cid:228) (cid:211) (cid:110) (cid:163) (cid:228) (cid:211) (cid:153) (cid:163) (cid:228) (cid:211) (cid:228) (cid:211) (cid:228) (cid:211) (cid:163) (cid:211) (cid:228) (cid:211) (cid:211) (cid:211) (cid:228) (cid:211) (cid:206) (cid:211) (cid:228) (cid:211) (cid:123) (cid:211) (cid:228) (cid:211) (cid:120) (cid:211) (cid:228) (cid:211) (cid:200) (cid:211) (cid:228) (cid:211) (cid:199) (cid:211) (cid:228) (cid:211) (cid:110) (cid:211) (cid:228) (cid:211) (cid:153) (cid:211) (cid:228) (cid:211) (cid:228) (cid:206) (cid:228) (cid:211) (cid:163) (cid:206) (cid:228) (cid:211) (cid:211) (cid:206) (cid:228) (cid:211) (cid:206) (cid:206) (cid:228) (cid:211) (cid:123) (cid:206) (cid:228) (cid:211) (cid:120) (cid:206) (cid:228) (cid:211) the delivery of our conventional growth plans as well as the construction of the Horizon Project and the Canadian Natural Upgrader. Under these plans we would expect to remain within our targeted range. Having this excess ﬁ nancial capacity means that Canadian Natural does not have to compromise on its balanced strategies. Maintaining a strong balance sheet provides ﬂ exibility to our operations and the execution of our deﬁ ned plan. (cid:32)(cid:105)(cid:204)(cid:202)(cid:105)(cid:62)(cid:192)(cid:152)(cid:136)(cid:152)(cid:125)(cid:195) (cid:173)(cid:10)(cid:102)(cid:202)(cid:147)(cid:136)(cid:143)(cid:143)(cid:136)(cid:156)(cid:152)(cid:195)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:120)(cid:206)(cid:153) (cid:200)(cid:206)(cid:153) (cid:163)(cid:93)(cid:228)(cid:120)(cid:228) (cid:163)(cid:93)(cid:123)(cid:228)(cid:120) (cid:163)(cid:93)(cid:123)(cid:228)(cid:206) (cid:12)(cid:136)(cid:219)(cid:136)(cid:96)(cid:105)(cid:152)(cid:96)(cid:195)(cid:202)(cid:171)(cid:105)(cid:192)(cid:202)(cid:86)(cid:156)(cid:147)(cid:147)(cid:156)(cid:152)(cid:202)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105) (cid:173)(cid:10)(cid:102)(cid:201)(cid:195)(cid:133)(cid:62)(cid:192)(cid:105)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:228)(cid:176)(cid:211)(cid:123) (cid:228)(cid:176)(cid:211)(cid:228) (cid:228)(cid:176)(cid:163)(cid:120) (cid:228)(cid:176)(cid:163)(cid:206) (cid:228)(cid:176)(cid:163)(cid:228) The Plan: Financial Plan 23 Health & Safety, Environment and Community OUR COMMITMENT TO RESPONSIBLE OPERATIONS “Doing it right” is part of our mission statement and integral to the way we approach our business. We continue to conduct our operations with diligence to ensure we comply with all regulatory standards and guidelines, and with the discipline and proactive focus to achieve continuous improvement in our stewardship performance. Our people and contractors understand they are accountable on a daily basis to implement our vision for health and safety, environment and community. HEALTH AND SAFETY PERFORMANCE: INCREASED AWARENESS, EFFECTIVE SYSTEMS AND CO-OPERATION We believe the continual improvements in our health and safety performance can be attributed to enhanced safety awareness in our operations, continuous improvement of our safety management systems, and a high degree of co-operation with our contractors in meeting health and safety goals. In our North American conventional operations, our total recordable injury frequency continued to decline in 2005 despite it being the most active in our history. Approximately 10 million more man hours were worked in 2005 than in 2004 with a reduction in the recordable injury frequency of 16%. Lost time injury and ﬁ rst aid injury frequencies have also continued to decrease during the past three years. As part of our proactive approach, the number of facility, rig, construction and pipeline safety and compliance audits performed in our conventional operations increased by nearly 50% over the number conducted in 2004. This aggressive audit program continues in 2006. Internationally, we implemented the key elements of our Safety, Health and Environment (“SHE”) Improvement Program, a key feature in our major accident hazard management strategy. At the Horizon Project, our Health and Safety team has assembled an extensive operational group to provide medical, safety and security support to the more than 2,000 people now working on- site. At year-end, all safety frequency statistics for the Horizon Project were better or comparable to statistics benchmarked against the Construction Owners Association of Alberta (COAA) for comparable projects. By year-end, Horizon Project had surpassed more than 3 million exposure hours without a Lost Time Accident. As Horizon Project activities increase in 2006, there is ongoing development of the Safety Management System, site procedures, and safety training programs. ENVIRONMENTAL INITIATIVES FOCUS ON CURRENT OPERATIONS AS WELL AS FUTURE DEVELOPMENTS Canadian Natural continues to invest in people, technologies, facilities and infrastructure to recover and process crude oil and natural gas resources efﬁ ciently in an environmentally sound manner. Our environmental strategies target energy efﬁ ciency, air emissions management, water quality, reduced fresh water use, and the minimization of our landscape footprint. Training and due diligence for operators and contractors are key to the effectiveness of our environmental management programs and the prevention of incidents. With a view to operational start-up of the Horizon Project in 2008, we are already addressing environmental aspects as diverse as the development of an audit/inspection package to encompass operations, the implementation of our wildlife corridor research program, and the construction of a fresh water lake to compensate for ﬁ sh bearing streams lost to development. In our conventional operations, our multi-year ﬂ aring and venting reduction strategy has signiﬁ cantly contributed to our air emission management programs. In 2005, Canadian Natural invested more than $15 million and completed more than 130 natural gas conservation projects with resulting recoveries in excess of 13 mmcf/d. In 2006, we plan to complete another 120 such natural gas conservation projects with a capital investment of $17 million. 24 The Plan: Health & Safety, Environment and Community Though Canadian Natural has signiﬁ cantly increased our heavy crude oil production, we have also been able to increase the percentage of solution gas conserved. In 2005, Canadian Natural continued to increase both the amount of solution gas that is collected and sold or utilized for lease fuel. Our solution gas conservation rate has increased from 63% in 2000 to 85% in 2005. (cid:1)(cid:143)(cid:76)(cid:105)(cid:192)(cid:204)(cid:62)(cid:202)(cid:195)(cid:156)(cid:143)(cid:213)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:105)(cid:192)(cid:219)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:192)(cid:62)(cid:204)(cid:105) (cid:173)(cid:175)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:105)(cid:192)(cid:219)(cid:105)(cid:96)(cid:174) (cid:153)(cid:228) (cid:110)(cid:120) (cid:110)(cid:228) (cid:199)(cid:120) (cid:199)(cid:228) (cid:200)(cid:120) (cid:200)(cid:228) (cid:211)(cid:228)(cid:228)(cid:228) (cid:211)(cid:228)(cid:228)(cid:163) (cid:211)(cid:228)(cid:228)(cid:211) (cid:211)(cid:228)(cid:228)(cid:206) (cid:211)(cid:228)(cid:228)(cid:123) (cid:211)(cid:228)(cid:228)(cid:120) Our Greenhouse Gas (GHG) emission reduction strategy is based on emissions intensity. Our goal is to consistently reduce GHG emissions per unit of production. We systematically and continuously review opportunities for emissions reduction at our facilities, and we are developing and implementing strategies that include technological solutions and stakeholder input. Since 2002, our emissions intensity has been reduced 13% despite signiﬁ cant increases in activity and production. At our primary heavy crude oil and in-situ oil sands operations our goal is to recycle produced water and supplement with brackish water, signiﬁ cantly reducing our fresh water use. At our Primrose operations we are now recycling about 95% of our produced water and have invested about $40 million in new brackish wells, pipelines and water treating capacity for our expanding operations. At our international operations, 2005 was the fourth year in succession where we achieved a decrease in total operational oil in produced water. We again exceeded our target of less than 25 parts per million (“ppm”) from our installations, well below statutory guidelines of 40 ppm. BUILDING FUTURES TOGETHER WITH COMMUNITIES Canadian Natural continues to build and maintain co-operative working relationships with our stakeholders, and to support communities in their quality of life initiatives. We encourage and welcome stakeholder input into our plans and ongoing operations. We are working collaboratively with many First Nation and Métis leaders near our operations. We continue to consult with First Nation and Métis communities related to reducing impacts on traditional lands and incorporating Traditional Environment Knowledge into our development and reclamation plans. Together, we have been identifying strategies and implementing action plans so communities can play a more direct role in the development of crude oil and natural gas resources. In 2005 we also increased ﬁ nancial and leadership support for Aboriginal education and training programs. We continue to expand our Building Futures Scholarship Program which supports training to help meet the human resource needs for oil and natural gas ﬁ eld operations. Since 2002, we have awarded more than $400,000 in scholarships to more than 300 students living in 26 communities near our operations. investment programs contribute to the Our community development of people and to the building of strong communities. We are proud to work with our communities in Western Canada, the UK and West Africa to provide ﬁ nancial and volunteer support for hundreds of projects that meet their vision for the future in education, wellness, arts, sports, and social programs. In our international operations, for example, we constructed a water tank tower and potable water network for the Adjue village in Côte d’Ivoire to help improve the lives and health of community members. In addition to the backing we provide to community programs and capital projects, our people throughout our operations in Western Canada have selected a variety of local community agencies that we support. Our corporate ofﬁ ce matches each dollar contributed by our employees and contractors to these important community agencies. The Plan: Health & Safety, Environment and Community 25 The Assets NORTH AMERICA 2005 net results, after royalties Proved reserves Production (mmboe) (mboe/d) 694 192 457 187 1,151 379 72 80 Oil and NGLs Natural gas Boe % of total DEFINED STRATEGY TO EXPLOIT A WORLD CLASS ASSET PORTFOLIO Our exploitation based development philosophy has proven through the business cycle to minimize exploration risks and maintain low operating and capital costs. This disciplined approach is applied rigorously throughout Canadian Natural’s worldwide operations. It includes: • Maintaining a large inventory of undeveloped land in each core region enabling us to continually high-grade prospects and to optimally plan future drilling programs. • Dominating the land base and controlling the infrastructure in regions in which we operate. We maintain high working interests and operate the vast majority of our assets allowing us to steward to our plans and control our costs. • Progressively developing lands as extensions from our existing infrastructure, thereby minimizing infrastructure costs. • Evaluating and testing new techniques to maximize resource recovery. • Maximizing our facility throughput, allowing us to reduce per-unit production costs. Whether is compressor utilization in Canadian natural gas operations, water and sand disposal in heavy crude oil operations or FPSO capacity utilization internationally, we aggressively seek opportunities to leverage capabilities and reduce per-unit costs. it NORTH AMERICAN NATURAL GAS North American natural gas is Canadian Natural’s single largest product, representing 43% of our equivalent production volumes and 46% of sales revenues in 2005. During 2005, average production volumes increased by 86 mmcf/d or 6%, reﬂ ecting both a strong drilling and asset development program and the full year impact of 2004 property acquisitions. Production is concentrated in four of our North American core regions: Northeast British Columbia, Northwest Alberta, the Northern Plains and the Southern Plains. We have a deﬁ ned ﬁ ve year development plan for each of these regions that results in 5% per annum production growth. NORTH AMERICAN CRUDE OIL AND NGLS Canadian Natural is one of Canada’s largest producers of crude oil and NGLs with an extensive developed and undeveloped light and heavy crude oil asset base augmented by NGLs which are produced in conjunction with natural gas. During 2005, average production volumes increased by 7%, reﬂ ecting our successful drilling and development programs. Our heavy crude oil production is concentrated in the Northern Plains core region with light crude oil being produced in all ﬁ ve of our core regions. Our exploitation based strategy capitalizes on our dominance in our core regions reducing both capital and operating costs. Our expertise in recovery techniques allows us to continually focus on maximizing crude oil recovery from both mature and new crude oil pools. 26 The Assets LYLE G. STEVENS Senior Vice-President, Exploitation JEFF W. WILSON Senior Vice-President, Exploration INTERNATIONAL 2005 net results, after royalties Proved reserves Production (mmboe) (mboe/d) 424 91 17 4 441 95 28 20 Oil and NGLs Natural gas Boe % of total INTERNATIONAL Our international operations provide a vehicle for continued light crude oil production growth. A disciplined and focused approach is essential to successful value creation in the international arena, therefore, we limit our exposure to those basins where we see the greatest opportunities and we can best lever our business strategies. We capitalize on our core competency of mature basin exploitation in the North Sea where the business parallels that of the WCSB in many ways. Offshore West Africa provides development opportunities and signiﬁ cant exploration upside, capitalizes on strong government relationships developed over the past few years and leverages the technical/operational expertise in the North Sea. In both basins, we operate in areas where we dominate the land base and have the infrastructure to support our operations. OIL SANDS MINING We hold extensive leases in the Athabasca region north of Fort McMurray that are amenable to the open pit mining of bitumen. These resources will be upgraded on site to a light sweet SCO and may be produced for decades to come without production declines normally associated with crude oil production. Our Horizon Oil Sands Project represents a phased development accessing up to 6 billion barrels of bitumen resource potential. Today we are in construction of the 110,000 bbl/d Phase 1 with ﬁ rst oil expected in the second half of 2008. Subsequent phases are planned with total potential production from the leases of approximately 500,000 bbl/d by 2017. The Assets 27 OIL SANDS MINING 2005 proved reserves Gross (mmbbl) 2,235 1,833 Net (mmbbl) 1,848 1,626 Bitumen SCO* * SCO reserves are based upon upgrading of the bitumen reserves. The reserves shown for bitumen and SCO are not additive. (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:87)(cid:69)(cid:83)(cid:84) (cid:33)(cid:76)(cid:66)(cid:69)(cid:82)(cid:84)(cid:65) (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:69)(cid:82)(cid:78) (cid:48)(cid:76)(cid:65)(cid:73)(cid:78)(cid:83) North American Natural Gas (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:69)(cid:65)(cid:83)(cid:84) (cid:34)(cid:82)(cid:73)(cid:84)(cid:73)(cid:83)(cid:72) (cid:35)(cid:79)(cid:76)(cid:85)(cid:77)(cid:66)(cid:73)(cid:65) (cid:35)(cid:33)(cid:46)(cid:33)(cid:36)(cid:33) (cid:53)(cid:51)(cid:33) (cid:51)(cid:79)(cid:85)(cid:84)(cid:72)(cid:69)(cid:82)(cid:78) (cid:48)(cid:76)(cid:65)(cid:73)(cid:78)(cid:83) (cid:51)(cid:79)(cid:85)(cid:84)(cid:72)(cid:69)(cid:65)(cid:83)(cid:84) (cid:51)(cid:65)(cid:83)(cid:75)(cid:65)(cid:84)(cid:67)(cid:72)(cid:69)(cid:87)(cid:65)(cid:78) NORTHEAST BRITISH COLUMBIA THE ASSET AND OUR PLAN Our experience in Northeast British Columbia, our large undeveloped land base of 2.0 million acres and 6,000 kilometers of pipelines affords us a signiﬁ cant competitive advantage in this highly prospective region. We further break this region down into three distinct geological play types: 1. Most northerly is the Helmet area where we employ horizontal wells to exploit the low-risk, regionally extensive, natural gas charged Jean Marie carbonate formation. 2. In the Fort St. John area, natural gas is produced from an array of carbonate and sandstone reservoirs ranging from the Notikewin at 2,000 ft to the Slave Point at 15,000 ft. 3. Most southerly is the Foothills region where we target deeper Mississippian and Triassic age reservoirs in this highly deformed structural area. 2005 ACTIVITY At Helmet, the Company drilled 46 net wells with an 85% success rate adding incremental production of 20 mmcf/d. In total, 228 net wells were drilled with a 88% success rate, including 57 net Notikewin natural gas wells. Since this shallow regional play was identiﬁ ed in late 2003, the Company has drilled 156 net wells on this trend with a success rate of 89%. We apportion a modest capital budget each year to explore for Slave Point reefs, targeting reservoirs with 5 to 30 bcf of recoverable natural gas. In 2005, 2.4 net Slave Point wells were drilled resulting in 1.4 net successful wells. In the Foothills of NE British Columbia and NW Alberta we are successfully increasing our exploration and development activity as we target deep Cretaceous reservoirs. Well costs are higher and pipeline infrastructure is less developed but rates and reserves are commensurately much higher. During 2005, 10 net wells targeting deep reservoirs were drilled that will add an estimated 35 mmcf/d of incremental production. 28 The Assets: North American Natural Gas WHAT TO EXPECT IN 2006 AND BEYOND The 2006 drilling program is well deﬁ ned with more than 260 wells planned, including 66 Notikewin wells and 30 horizontal wells at Helmet. On the exploration front, four deep natural gas wells are planned targeting the Slave Point formation. Our project inventory is deep with more than 1,500 well locations planned over the next ﬁ ve years. Our large undeveloped land base and our superior inventory of drilling prospects in the proliﬁ c relatively undeveloped basin of NE British Columbia creates one of the key drivers for our future natural gas growth. We project resource potential of 1.2 tcf in our 5-year forecast for this core region. NORTHWEST ALBERTA THE ASSET AND OUR PLAN This region contains exceptional exploration and exploitation opportunities in combination with our extensive, owned and operated infrastructure. We produce liquids rich natural gas from multiple, often technically complex horizons, with formation depths ranging from 2,000 to 15,000 feet. We leverage our existing developments to exploit existing pools while continuing to develop unconventional and tight gas plays. Landholdings in the region exceed 1.5 million undeveloped acres and we own and operate more than 26 facilities and 1,800 miles of pipelines to support our operations. 2005 ACTIVITY In this region we drilled a total of 166 net natural gas wells, a 17 net well increase from 2004. We continued our low- risk Cardium sand development, drilling 76 net wells with a remarkable 99% success rate. The focus of our excellent technical team on this complex tight sand reservoir has resulted in a previously costly and risky play becoming a low-risk exploitation development. We are now leveraging the Cardium play in this region to economically access deeper horizons. (cid:45)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:118)(cid:213)(cid:143)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96) (cid:173)(cid:152)(cid:105)(cid:204)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:200)(cid:211) (cid:123)(cid:199)(cid:200) (cid:110)(cid:153)(cid:228) (cid:200)(cid:110)(cid:153) (cid:199)(cid:199)(cid:199) (cid:32)(cid:156)(cid:192)(cid:204)(cid:133)(cid:202)(cid:1)(cid:147)(cid:105)(cid:192)(cid:136)(cid:86)(cid:62)(cid:152)(cid:202)(cid:152)(cid:62)(cid:204)(cid:213)(cid:192)(cid:62)(cid:143)(cid:202)(cid:125)(cid:62)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:93)(cid:202)(cid:76)(cid:105)(cid:118)(cid:156)(cid:192)(cid:105)(cid:202)(cid:192)(cid:156)(cid:222)(cid:62)(cid:143)(cid:204)(cid:136)(cid:105)(cid:195) (cid:173)(cid:147)(cid:147)(cid:86)(cid:118)(cid:201)(cid:96)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:163)(cid:93)(cid:123)(cid:163)(cid:200) (cid:163)(cid:93)(cid:206)(cid:206)(cid:228) (cid:163)(cid:93)(cid:211)(cid:123)(cid:120) (cid:163)(cid:93)(cid:211)(cid:228)(cid:123) (cid:153)(cid:228)(cid:200) In the northern portion of this core area we continued to expand our multi-zone drilling program and also extended the shallow Notikewin play ﬁ rst developed in Northeast British Columbia. WHAT TO EXPECT IN 2006 AND BEYOND The 2006 drilling program includes almost 150 net wells, with large programs for the Cardium, 57 net wells, and the Notikewin, 13 net wells. We have identiﬁ ed more than 950 locations to be drilled over the next ﬁ ve years in this core area. Through delineation drilling, technical analysis and land acquisitions we have secured a competitive advantage in the deep basin in this region and we foresee signiﬁ cant potential from this play type. Our expertise in the region coupled with our extensive undeveloped land base creates a strong natural gas growth proﬁ le and the second core area that will drive our corporate natural gas growth. Here we target new natural gas resource potential of 1.3 tcf over the next ﬁ ve years. NORTHERN PLAINS THE ASSET AND OUR PLAN Natural gas in the Northern Plains core region is produced from shallow, low-risk, multi-zone prospects and more recently from the Horseshoe Canyon coal bed methane (“CBM”). This is generally considered a mature operating region however through ongoing focused exploitation we continue to ﬁ nd excellent prospects for both development drilling and secondary zone recompletions. Our strategy in this region is to target low-risk exploration and development opportunities on our extensive land base, continue expansion of our commercial CBM project, examine synergistic property acquisitions opportunities, and minimize operating costs through high utilization of facilities and operations discipline. 2005 ACTIVITY During 2005, 238 net wells targeting natural gas were drilled in the region with a 84% success rate. CBM development drilling continued to grow with the drilling of 42 net wells. We believe that our asset base is capable of delivering continued growth over the next 5 years. WHAT TO EXPECT IN 2006 AND BEYOND The 2006 drilling program includes 353 net natural gas wells and recompletion of 299 net wells. Over the next ﬁ ve years we have identiﬁ ed over 1,700 net natural gas locations, including 510 net Horseshoe Canyon CBM locations and more than 800 recompletion opportunities. SOUTHERN PLAINS THE ASSET AND OUR PLAN Natural gas in the Southern Plains core region is produced from shallow, low-risk wells drilled at high densities, conventional multi-zone and additional CBM prospects. We’ve operated in this core region for 10 years and expect to grow production by an average of 4% per annum for the next 5 years. We continue to regionally expand the prospective area for shallow gas resulting in new inﬁ ll drilling opportunities and new shallow plays in undeveloped areas. We have maximized our returns on shallow gas and CBM by utilizing our area dominance and existing infrastructure to add low-cost volumes. 2005 ACTIVITY The 2005 drilling program, at 342 net wells, represented a 47% increase over 2004 activity when capital was redeployed towards property acquisitions. This 2005 program included 209 net shallow natural gas wells, 58 net CBM wells and 75 net other natural gas wells. WHAT TO EXPECT IN 2006 AND BEYOND The 2006 drilling program is comprised of more than 375 net wells, almost 250 of which are targeting low-risk, shallow natural gas. 60 net Horseshoe Canyon CBM wells are planned as the Company continues to expand both its expertise and its commercial CBM operations. Our ﬁ ve year drilling inventory totals more than 1,550 net natural gas wells, including over 1,070 shallow locations and over 170 net Horseshoe Canyon CBM wells. With the addition of new shallow gas prospects and continued Horseshoe Canyon CBM development we are forecasting modest production growth in the Southern Plains over the next ﬁ ve years. The Assets: North American Natural Gas 29 North American Crude Oil LIGHT CRUDE OIL AND NGLS THE ASSET AND OUR PLAN We produce light crude oil and NGLs in all of the Company’s western Canadian core regions. In North America, our light oil assets are largely developed; however, we continue to grow light oil production through a strategy of new waterﬂ ood implementation, existing waterﬂ ood optimization, development drilling, new pool discoveries and acquisitions. The vast majority of the Company’s light pools are produced under waterﬂ ood resulting in high recovery factors and low production decline rates. 2005 ACTIVITY In 2005, Canadian Natural’s light crude oil drilling and development programs pursued four initiatives: • Low risk, inﬁ ll drilling in crude oil pools located in the Northern Plains, Northwest Alberta and the Southeast Saskatchewan core regions; • Waterﬂ ood optimization programs in all our core regions. We have a strong technical team that is dedicated solely to waterﬂ ood optimization through detailed reservoir characterization, analysis of pattern performance, improved well operating practices and improved ﬂ uid processing at our facilities; • New pool exploration and pool extensions in Northwest Alberta and Northeast British Columbia where 1,000 bbl/d of new production was added. Future development potential was also identiﬁ ed; and, • Pilot testing of polymer ﬂ ooding to improve oil recovery in a mature waterﬂ ood. WHAT TO EXPECT IN 2006 AND BEYOND For 2006, Canadian Natural will continue to focus on waterﬂ ood and tertiary recovery opportunities. Our 2005 drilling program has identiﬁ ed signiﬁ cant new development potential in the Fireweed area of Northeast British Columbia, the Worsley area of Northwest Alberta and the Pierson pool in Southeast Saskatchewan. More than 120 net wells are planned for our 2006 light crude oil drilling program making it the largest light crude oil program in the Company’s history. 30 The Assets: North American Crude Oil Canadian Natural will focus on waterﬂ ood enhancements to add incremental light crude oil reserves. We estimate that just a 1% improvement in recovery factor could yield an incremental 42 million barrels of reserves. In addition to the enhanced crude oil recovery initiatives our deﬁ ned plan includes over 400 new well locations to be drilled over the next ﬁ ve years. PELICAN LAKE CRUDE OIL THE ASSET AND OUR PLAN This massive, shallow crude oil pool in our Northern Plains core region is estimated to contain up to 3 billion barrels of OOIP and continues to provide excellent opportunities for production and reserves growth. We developed this pool exclusively with horizontal wells to minimize the environmental impact, reduce development costs and provide greater well productivity. We own and operate three centralized treating facilities in the area. Although priced similarly to heavy crude oil, our Pelican Lake crude oil production yields netbacks typical of medium crude oil due to our ability to maintain low operating costs. 2005 ACTIVITY At Pelican Lake 2005 proved to be very successful year: • We continued to extend the developable area of the existing pool and drilled 52 net primary horizontal wells; • 8 net stratigraphic wells were drilled to identify further pool extensions and other new pools in the area; • We continued to expand the commercial waterﬂ ood project and have now converted 11% of our ﬁ eld to waterﬂ ood. A total of 25 sections are under waterﬂ ood with 64 net production wells and 72 net injection wells; and, • We initiated a ﬁ ve well pilot test to determine the viability of polymer ﬂ ooding with the goal of enhancing productivity and increasing oil recovery. Initial results are promising and lead to a commercial scale installation in 2006. Application of EOR techniques to the 3 billion barrels of OOIP, combined with new drilling locations will continue to ramp Pelican Lake production levels. (cid:45)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:118)(cid:213)(cid:143)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96) (cid:173)(cid:152)(cid:105)(cid:204)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:211)(cid:120)(cid:200) (cid:211)(cid:211)(cid:110) (cid:200)(cid:163)(cid:211) (cid:206)(cid:163)(cid:199) (cid:123)(cid:123)(cid:200) The waterﬂ ood, primary production drilling and continued optimization has reversed production declines in the ﬁ eld resulting in a 10 mbbl/d or 57% production increase from 2004. WHAT TO EXPECT IN 2006 AND BEYOND The 2006 program will see Canadian Natural drilling 126 net horizontal wells for primary production and 14 additional net stratigraphic wells to delineate pool extensions. Expansion of the Pelican Lake waterﬂ ood remains a priority and we plan to complete the conversion of 7 sections to waterﬂ ood. This will entail drilling 24 net horizontal inﬁ ll production wells and converting 10 net producing wells into water injection wells. Secondary recovery processes are expected to double primary recovery factors on approximately 45 to 55% of the ﬁ eld. Beyond waterﬂ ood implementation, we will continue to evaluate the use of polymer at our pilot test to enhance waterﬂ ood recovery. While it is too early to judge the technical and economic success of this enhanced recovery process, polymer ﬂ ood could yield incremental recoveries of 15% over primary production. This could amount to 130 mmbbl of incremental recovery at Pelican Lake. (cid:41)(cid:78)(cid:74)(cid:69)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78) (cid:38)(cid:76)(cid:85)(cid:73)(cid:68)(cid:83) We currently expect that with our EOR projects combined with over 600 net well locations in our ﬁ ve year plan will continue to increase production over the next several years. (cid:41)(cid:78)(cid:74)(cid:69)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78) (cid:48)(cid:85)(cid:77)(cid:80) (cid:41)(cid:78)(cid:74)(cid:69)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78) (cid:55)(cid:69)(cid:76)(cid:76) — CASE STUDY — PELICAN LAKE Pelican Lake is a large, shallow oil pool in Canadian Natural’s Northern Plains core region estimated to contain up to 3 billion barrels of OOIP and is exclusively developed with horizontal wells. Optimization of the Field continues on several fronts as follows: • We now drill wells with both single and multiple leg “tuning fork” wells efﬁ ciently draining more of the reservoir from each well. Our expected well inventory remains strong over the next ﬁ ve year period; • Application of waterﬂ ood technology to a portion of the Field could increase recovery factors by a further 7.5% from the base expected recovery of about 5%; • Application of Polymer ﬂ ood (see ﬁ gure) could increase recovery factors by 15% throughout the majority of the Field. Our initial pilot test for this ﬂ ood commenced in early 2005 with preliminary results expected in 2006. As a result of these initiatives, Pelican Lake production increased 57% during the year, reversing 3 years of production declines. Continued growth is expected in production volumes for the next ﬁ ve years, once again making Pelican Lake a growth story. (cid:48)(cid:47)(cid:44)(cid:57)(cid:45)(cid:37)(cid:50)(cid:0)(cid:41)(cid:46)(cid:42)(cid:37)(cid:35)(cid:52)(cid:41)(cid:47)(cid:46)(cid:0)(cid:38)(cid:44)(cid:47)(cid:47)(cid:36)(cid:41)(cid:46)(cid:39) (cid:48)(cid:82)(cid:79)(cid:68)(cid:85)(cid:67)(cid:84)(cid:73)(cid:79)(cid:78) (cid:55)(cid:69)(cid:76)(cid:76) (cid:47)(cid:73)(cid:76) (cid:44)(cid:69)(cid:65)(cid:68)(cid:73)(cid:78)(cid:71)(cid:0)(cid:37)(cid:68)(cid:71)(cid:69) (cid:79)(cid:70)(cid:0)(cid:47)(cid:73)(cid:76)(cid:0)(cid:34)(cid:65)(cid:78)(cid:75) (cid:33)(cid:68)(cid:68)(cid:73)(cid:84)(cid:73)(cid:79)(cid:78)(cid:65)(cid:76)(cid:0)(cid:47)(cid:73)(cid:76)(cid:0)(cid:50)(cid:69)(cid:67)(cid:79)(cid:86)(cid:69)(cid:82)(cid:89) (cid:8)(cid:47)(cid:73)(cid:76)(cid:0)(cid:34)(cid:65)(cid:78)(cid:75)(cid:9) (cid:48)(cid:79)(cid:76)(cid:89)(cid:77)(cid:69)(cid:82)(cid:0)(cid:51)(cid:79)(cid:76)(cid:85)(cid:84)(cid:73)(cid:79)(cid:78) (cid:52)(cid:65)(cid:80)(cid:69)(cid:82)(cid:69)(cid:68)(cid:0)(cid:48)(cid:79)(cid:76)(cid:89)(cid:77)(cid:69)(cid:82)(cid:0)(cid:51)(cid:76)(cid:85)(cid:71) (cid:36)(cid:82)(cid:73)(cid:86)(cid:73)(cid:78)(cid:71)(cid:0)(cid:38)(cid:76)(cid:85)(cid:73)(cid:68)(cid:0)(cid:8)(cid:55)(cid:65)(cid:84)(cid:69)(cid:82)(cid:9) (cid:46)(cid:47)(cid:52)(cid:37)(cid:26)(cid:0)(cid:41)(cid:76)(cid:76)(cid:85)(cid:83)(cid:84)(cid:82)(cid:65)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:79)(cid:78)(cid:0)(cid:72)(cid:79)(cid:87)(cid:0)(cid:80)(cid:79)(cid:76)(cid:89)(cid:77)(cid:69)(cid:82)(cid:0)(cid:87)(cid:79)(cid:82)(cid:75)(cid:83)(cid:0)(cid:73)(cid:78)(cid:0)(cid:65)(cid:0)(cid:71)(cid:69)(cid:78)(cid:69)(cid:82)(cid:73)(cid:67)(cid:0)(cid:79)(cid:73)(cid:76)(cid:70)(cid:73)(cid:69)(cid:76)(cid:68)(cid:14)(cid:0)(cid:46)(cid:79)(cid:84)(cid:0)(cid:65)(cid:0)(cid:84)(cid:82)(cid:85)(cid:69)(cid:0) (cid:82)(cid:69)(cid:80)(cid:82)(cid:69)(cid:83)(cid:69)(cid:78)(cid:84)(cid:65)(cid:84)(cid:73)(cid:79)(cid:78)(cid:0)(cid:79)(cid:70)(cid:0)(cid:48)(cid:69)(cid:76)(cid:73)(cid:67)(cid:65)(cid:78)(cid:0)(cid:44)(cid:65)(cid:75)(cid:69)(cid:12)(cid:0)(cid:87)(cid:72)(cid:73)(cid:67)(cid:72)(cid:0)(cid:73)(cid:83)(cid:0)(cid:65)(cid:0)(cid:70)(cid:76)(cid:79)(cid:79)(cid:68)(cid:0)(cid:79)(cid:70)(cid:0)(cid:80)(cid:65)(cid:82)(cid:65)(cid:76)(cid:76)(cid:69)(cid:76)(cid:0)(cid:72)(cid:79)(cid:82)(cid:73)(cid:90)(cid:79)(cid:78)(cid:84)(cid:65)(cid:76)(cid:0)(cid:87)(cid:69)(cid:76)(cid:76)(cid:83)(cid:14) The Assets: North American Crude Oil 31 North American Crude Oil (continued) PRIMARY HEAVY CRUDE OIL THE ASSET AND OUR PLAN Canadian Natural’s historic growth in primary heavy crude oil production has been achieved through drilling as well as strategic, synergistic acquisitions. Heavy crude oil is produced using primary production mechanisms from shallow, low-risk, multi-zone wells. This leads to low ﬁ nding and development costs, exceptional drilling success rates and many subsequent recompletion opportunities. The region is also natural gas prone and development drilling can lead to both natural gas and heavy crude oil discoveries. With over 1.6 million acres of undeveloped land and 200,000 acres of developed land, we dominate production and operations within the Bonnyville/Lloydminster primary producing area of our Northern Plains core region. This dominance allows us to minimize capital by conducting large scale drilling and development programs. We also minimize and control our production costs through owning and operating central treating facilities, maximizing their utilization and using our size to achieve economies of scale. Finally, ownership of the ECHO crude oil sales pipeline reduces our transportation costs and allows us to be the only producer capable of delivering undiluted heavy crude oil into our blending facilities at Hardisty, Alberta. 2005 ACTIVITY During 2005 we drilled 360 heavy crude oil net wells, a 180 net well increase from 2004. Our ongoing program of recompletions continues to add low-cost volumes and in 2005 483 net wells were recompleted to secondary zones. In our efforts to improve crude oil recovery beyond primary we initiated a heavy crude oil waterﬂ ood at our Lonerock Field and are ﬁ eld testing an experimental solvent injection scheme at Lindbergh. WHAT TO EXPECT IN 2006 For 2006, 344 locations are forecast to be drilled and a further 340 net wells will be recompleted. Our deﬁ ned growth plan forecasts that over 1,675 net well locations will be drilled during the next ﬁ ve years, keeping production relatively ﬂ at. As new markets are created for heavy crude oil we have the capability 32 The Assets: North American Crude Oil of ramping up this drilling effort and increasing production, however, we will not proceed until we are assured of this new demand. We will continue to pursue the development of applicable technologies to further improve oil recovery and are currently conducting research in both the ﬁ eld and the labratory. We estimate our developed lands to contain 7 billion to 10 billion barrels of OOIP; a modest 1% increase in recovery would equate to over 70 million barrels of incremental recoverable crude oil. THERMAL (IN-SITU) HEAVY CRUDE OIL THE ASSET AND OUR PLAN Canadian Natural has some of the best thermal oil sands assets in Canada. In the Cold Lake region we have our commercial Cyclic Steam Stimulation (CSS) project whose production makes us the second largest thermal crude oil producer in Canada. In the immediate region we also have the undeveloped Primrose East lease which will provide for future growth using the same proven recovery process. In the Athabasca region we have more than 200,000 undeveloped acres of land suitable for thermal recovery processes. These assets coupled with the proposed Canadian Natural upgrader initiative would provide both short and long term growth for the Company. Our technical expertise, our asset base and years of experience operating and constructing thermal projects has placed Canadian Natural as an industry leader in thermal in-situ oil recovery. 2005 ACTIVITY Our primary 2005 focus was the construction and start-up of the Primrose North expansion project. This project consists of a satellite steam generation plant and, 4 new well pads with 96 net horizontal wells that are pipeline connected to our central Wolf Lake processing plant. The expansion project was completed on budget and on schedule allowing for steam injection in Q4 2005 and production in January 2006. As a result of continued development and optimization at our Primrose South project, our thermal oil production reached record levels, over 53 mbbl/d, which was a 22% increase over 2004. (cid:32)(cid:156)(cid:192)(cid:204)(cid:133)(cid:202)(cid:1)(cid:147)(cid:105)(cid:192)(cid:136)(cid:86)(cid:62)(cid:152)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:62)(cid:152)(cid:96)(cid:202)(cid:32)(cid:20)(cid:29)(cid:195)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152) (cid:173)(cid:147)(cid:76)(cid:76)(cid:143)(cid:201)(cid:96)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:211)(cid:211)(cid:211) (cid:211)(cid:228)(cid:200) (cid:163)(cid:199)(cid:120) (cid:163)(cid:200)(cid:153) (cid:163)(cid:200)(cid:199) We are the second largest producer of crude oil recovered by thermal processes in Canada. WHAT TO EXPECT IN 2006 AND BEYOND For 2006, production from the Primrose North expansion project will reach its design capacity of 30 mbbl/d by the start of Q4. In 2006, we plan to drill an additional 75 net horizontal wells at Primrose as part of the ongoing project. As part of our long term thermal project expansion plans we will also drill more than 220 net stratigraphic wells to further deﬁ ne our leases at Primrose East, Kirby, Birch Mountain and Gregoire Lake. We will also continue to delineate further reservoir at Primrose South to maximize both resource recovery and the infrastructure utilization. Mid-term growth will come from the commercial development at Primrose East where production is expected in 2009. The regulatory application for this project was submitted in January, 2006. Beyond 2009 we see the potential to add an incremental 240 mbbl/d of thermal in-situ production from our Athabasca oil sands leases at Kirby, Birch Mountain East, and Gregoire Lake. This new bitumen production will serve as feedstock for both the proposed Canadian Natural upgrader and the Horizon upgrader. IN-SITU LANDS (cid:34)(cid:73)(cid:82)(cid:67)(cid:72)(cid:0)(cid:45)(cid:79)(cid:85)(cid:78)(cid:84)(cid:65)(cid:73)(cid:78) (cid:8)(cid:55)(cid:14)(cid:0)(cid:40)(cid:79)(cid:82)(cid:73)(cid:90)(cid:79)(cid:78)(cid:9) (cid:33) (cid:52) (cid:50) (cid:37) (cid:34) (cid:44) (cid:33) (cid:46) (cid:33) (cid:55) (cid:37) (cid:40) (cid:35) (cid:52) (cid:33) (cid:43) (cid:51) (cid:33) (cid:51) (cid:39)(cid:82)(cid:69)(cid:71)(cid:79)(cid:73)(cid:82)(cid:69) (cid:43)(cid:73)(cid:82)(cid:66)(cid:89) (cid:48)(cid:82)(cid:73)(cid:77)(cid:82)(cid:79)(cid:83)(cid:69) (cid:48)(cid:82)(cid:73)(cid:77)(cid:65)(cid:82)(cid:89) (cid:40)(cid:69)(cid:65)(cid:86)(cid:89)(cid:0)(cid:47)(cid:73)(cid:76) — CASE STUDY — CANADIAN NATURAL UPGRADER We are the second largest producer of crude oil recovered by thermal processes in Canada with 2005 combined average daily production of 53 mbbl/d from our three in-situ developments. Beyond this, we a vast heavy crude oil resource base capable of generating signiﬁ cant returns for our shareholders. In order to capitalize on this opportunity we are proposing to build a heavy crude oil upgrader in Alberta which would convert this feedstock into a light sweet synthetic crude oil. This would signiﬁ cantly reduce the marketing risk of the production while increasing the expected realizations from its sale. It helps facilitate the development of these vast resources in a disciplined and stepwise manner. During 2006 we will expend $30 million on a Scoping Study to determine the preferred location, technology, capital cost and crude oil output quality. We will also examine the use of gasiﬁ cation technologies to further control production expense. Resulting recommendations for the Upgrader will be tabled in 2007. Following a disciplined emphasis on front end engineering we expect construction to commence in 2009 and ﬁ rst production in 2012. Preliminary capacity estimates are for 125 mbbl/d of SCO, expandable to 175 mbbl/d by 2015. The proposed Canadian Natural Upgrader, by increasing average realizations and netbacks while expanding markets for our heavy crude oil will generate signiﬁ cant shareholder value for years to come. The Assets: North American Crude Oil 33 (cid:45)(cid:213)(cid:86)(cid:86)(cid:105)(cid:195)(cid:195)(cid:118)(cid:213)(cid:143)(cid:202)(cid:22)(cid:152)(cid:204)(cid:105)(cid:192)(cid:152)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:202)(cid:86)(cid:192)(cid:213)(cid:96)(cid:105)(cid:202)(cid:156)(cid:136)(cid:143)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:202)(cid:96)(cid:192)(cid:136)(cid:143)(cid:143)(cid:105)(cid:96) (cid:173)(cid:152)(cid:105)(cid:204)(cid:202)(cid:220)(cid:105)(cid:143)(cid:143)(cid:195)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:110) (cid:206) (cid:163)(cid:120) (cid:163)(cid:163) (cid:163)(cid:211) We operate approximately 99% of our production with an average ownership interest of 80%. Operations are currently run from four hubs. By maintaining control of these assets we have been able to control the capital allocation and pace of our exploitation plans for the properties. International UNITED KINGDOM PORTION OF THE NORTH SEA THE ASSET AND OUR PLAN Our achievements are a result of the successful utilization of our mature basin exploitation expertise. The ﬁ rst stage is based upon optimizing existing facilities and waterﬂ oods. We inﬁ ll drill, recomplete, and workover wells and optimize waterﬂ oods to increase production, lower costs and extend ﬁ eld life. The second stage incorporates more near pool development and exploration in order to maximize utilization of common facilities and ultimately extend all ﬁ elds’ economic lives. In 2006 and beyond, increasing emphasis on this type of work will be made. We believe that the current environment within the North Sea is similar to that of the WCSB in the early 1990s. The basin is mature and many of the major operators are reducing activity levels or looking at divestiture of properties. Exploitation oriented companies like Canadian Natural are proactively pursuing such opportunities. 2005 ACTIVITY During 2005 we drilled 13.2 net wells and 0.9 service and injection wells, effectively offsetting production declines. At the Murchison Hub, production from the satellite pool Playfair continued, however third party natural gas export restrictions resulted in some curtailments of crude oil production. At the Ninian Hub, work progressed on the Columba Terrace and Lyell (cid:52)(cid:73)(cid:70)(cid:70)(cid:65)(cid:78)(cid:89) (cid:52)(cid:79)(cid:78)(cid:73) (cid:52)(cid:72)(cid:69)(cid:76)(cid:77)(cid:65) (cid:34)(cid:65)(cid:76)(cid:77)(cid:79)(cid:82)(cid:65)(cid:76) (cid:53)(cid:14)(cid:43)(cid:14) (cid:35)(cid:69)(cid:78)(cid:84)(cid:82)(cid:65)(cid:76) (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:0)(cid:51)(cid:69)(cid:65) (cid:33)(cid:66)(cid:69)(cid:82)(cid:68)(cid:69)(cid:69)(cid:78) (cid:34)(cid:65)(cid:78)(cid:70)(cid:70) Field developments with engineering of subsea raw seawater injection facilities. In the Central North Sea, production from at the Banff/Kyle Hub was consolidated into one FPSO, reducing operating costs and extending the economic life of both ﬁ elds. The natural gas reinjection plan at Banff resulted in lower natural gas production volumes when compared with 2004, but should ultimately increase recoverability of crude oil from the reservoir. Refurbishment of the Tiffany Platform drilling rig was completed and a third party well was drilled and tariff income agreement was completed. WHAT TO EXPECT IN 2006 AND BEYOND During 2006, 15 net wells are expected to be drilled, including 3 injector wells. At Murchison and Ninian Hubs we will increase water injection and processing throughput. At the Lyell Field, 4 new wells with artiﬁ cial lift and an aggressive waterﬂ ood are part of the longer term plan to add approximately 20 mbbl/d of new plateau production in 2008. With our current exploitation portfolio we expect to maintain or slightly grow current production levels over the next 3-4 years, but we continue to look for accretive acquisitions with exploitation upside for growth. (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:69)(cid:82)(cid:78) (cid:46)(cid:79)(cid:82)(cid:84)(cid:72)(cid:0)(cid:51)(cid:69)(cid:65) (cid:48)(cid:76)(cid:65)(cid:89)(cid:70)(cid:65)(cid:73)(cid:82) (cid:45)(cid:85)(cid:82)(cid:67)(cid:72)(cid:73)(cid:83)(cid:79)(cid:78) (cid:44)(cid:89)(cid:69)(cid:76)(cid:76) (cid:51)(cid:84)(cid:82)(cid:65)(cid:84)(cid:72)(cid:83)(cid:80)(cid:69)(cid:89) (cid:43)(cid:89)(cid:76)(cid:69) (cid:46)(cid:73)(cid:78)(cid:73)(cid:65)(cid:78) (cid:35)(cid:79)(cid:76)(cid:85)(cid:77)(cid:66)(cid:65) 34 The Assets: International (cid:22)(cid:152)(cid:204)(cid:105)(cid:192)(cid:152)(cid:62)(cid:204)(cid:136)(cid:156)(cid:152)(cid:62)(cid:143)(cid:202)(cid:204)(cid:156)(cid:204)(cid:62)(cid:143)(cid:202)(cid:171)(cid:192)(cid:156)(cid:96)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152) (cid:173)(cid:147)(cid:76)(cid:156)(cid:105)(cid:201)(cid:96)(cid:174) (cid:228)(cid:120) (cid:228)(cid:123) (cid:228)(cid:206) (cid:228)(cid:211) (cid:228)(cid:163) (cid:153)(cid:120) (cid:110)(cid:200) (cid:199)(cid:200) (cid:120)(cid:228) (cid:123)(cid:163) ALLEN M. KNIGHT Senior Vice-President, International & Corporate Development OFFSHORE WEST AFRICA THE ASSET AND OUR PLAN Canadian Natural has three exploration Blocks comprising approximately 274 thousand net undeveloped acres of land located offshore Côte d’Ivoire. We are currently continuing the development of three proved properties East Espoir, West Espoir and Baobab. East Espoir and Baobab are in production with further drilling continuing, whilst West Espoir will commence development drilling in Q2 2006. 2005 ACTIVITY In Côte d’Ivoire in 2005 we drilled an additional two new net in- ﬁ ll wells at East Espoir, tapping undeveloped portions of the pool and increasing production by 5 mbbl/d. Also during the year, ﬁ rst oil at our Baobab medium crude oil development was achieved on-budget in August 2005 with only 4.5 years elapsed from ﬁ rst discovery to ﬁ rst oil – an excellent cycle time for our ﬁ rst deepwater development. Our West Espoir development also continued on time and on budget with ﬁ rst oil expected in the second half of 2006. During the year the well head tower was installed on location and the drilling conductors were driven to depth. In October 2005, Canadian Natural completed the acquisition of the permit to develop the Olowi Field, offshore Gabon. The permit comprises a 90% interest in the production sharing agreement for the Block containing the Olowi Field, located 20 kilometers offshore and in 30 meters of water. Olowi has been delineated by the drilling of 15 wells by the previous owner and potentially contains as much as 500 million barrels of 34˚ API light crude OOIP. (cid:44)(cid:73)(cid:66)(cid:82)(cid:69)(cid:86)(cid:73)(cid:76)(cid:76)(cid:69) (cid:8)(cid:94)(cid:21)(cid:20)(cid:21)(cid:0)(cid:75)(cid:77)(cid:9) (cid:39)(cid:33)(cid:34)(cid:47)(cid:46) (cid:47)(cid:76)(cid:79)(cid:87)(cid:73) (cid:33)(cid:84)(cid:76)(cid:65)(cid:78)(cid:84)(cid:73)(cid:67)(cid:0)(cid:47)(cid:67)(cid:69)(cid:65)(cid:78) WHAT TO EXPECT IN 2006 AND BEYOND For 2006, two more producer wells will be drilled at East Espoir and 3 wells at Baobab, essentially completing initial development. West Espoir is scheduled for ﬁ rst oil during the second half of 2006 following completion of production infrastructure and drilling of the ﬁ rst of 3 producer wells. Essentially, we will have grown our production in Côte d’Ivoire from no production at the start of 2002 to about 60,000 boe/d through these three developments – all at highly attractive economics. Beyond current developments, the nearby Acajou Field will eventually be tied back to the East Espoir as space becomes available in these facilities. Again, we leverage existing facilities to maximize recovery of economic reserves. The Olowi development plan, comprising an FPSO and four drilling towers was ﬁ led with the Gabon Government in late 2005 and was approved for execution in early 2006. Following engineering design and request for tenders, the development will commence in late 2006 with ﬁ rst production targeted for late 2008 and a plateau production rate of 20 mbbl/d. We plan to leverage our reputation and experience in the region to capture additional exploration and exploitation opportunities within this core region. (cid:35)(cid:189)(cid:52)(cid:37)(cid:0)(cid:36)(cid:7)(cid:41)(cid:54)(cid:47)(cid:41)(cid:50)(cid:37) (cid:33)(cid:66)(cid:73)(cid:68)(cid:74)(cid:65)(cid:78) (cid:42)(cid:65)(cid:67)(cid:81)(cid:85)(cid:69)(cid:86)(cid:73)(cid:76)(cid:76)(cid:69) (cid:55)(cid:69)(cid:83)(cid:84)(cid:0)(cid:37)(cid:83)(cid:80)(cid:79)(cid:73)(cid:82) (cid:37)(cid:65)(cid:83)(cid:84)(cid:0)(cid:37)(cid:83)(cid:80)(cid:79)(cid:73)(cid:82) (cid:38)(cid:79)(cid:88)(cid:84)(cid:82)(cid:79)(cid:84) (cid:48)(cid:65)(cid:78)(cid:84)(cid:72)(cid:69)(cid:82)(cid:69) (cid:45)(cid:65)(cid:78)(cid:84)(cid:65) (cid:34)(cid:65)(cid:79)(cid:66)(cid:65)(cid:66) (cid:33)(cid:67)(cid:65)(cid:74)(cid:79)(cid:85) (cid:43)(cid:79)(cid:83)(cid:83)(cid:73)(cid:80)(cid:79) (cid:33)(cid:84)(cid:76)(cid:65)(cid:78)(cid:84)(cid:73)(cid:67)(cid:0)(cid:47)(cid:67)(cid:69)(cid:65)(cid:78) The Assets: International 35 THE PEOPLE We have assembled a world-class team of oil sands mining and project management experts. THE PLAN Our disciplined approach is based upon a heavy emphasis on front end design and engineering. THE ASSETS We estimate our leases to contain up to 16 billion barrels of bitumen resource potential with up to 6 billion of that amenable to open pit mining. Horizon Project HORIZON THE ASSET AND OUR PLAN Canadian Natural owns 115,796 acres in the Athabasca Oil Sands area of Northern Alberta, about 70 km north of Fort McMurray. The Horizon Oil Sands Project includes a surface oil sands mining and bitumen extraction plant coupled with on-site bitumen upgrading and associated infrastructure to produce a 34º API synthetic crude oil. THE HORIZON ADVANTAGE The technology at the Horizon Project is based on that currently in use at existing plants, effectively mitigating technology risk in Phase 1. That being said, our plant has been conﬁ gured in a manner to maximize beneﬁ ts from the technologies. For example, the Horizon Project will have a very high level of heat sharing and integration between the facilities, reducing both natural gas consumption and greenhouse gas emission levels. The project is designed as a phased development. First production of 110 mbbl/d of SCO from Phase 1 construction is targeted to commence in the second half of 2008. Production is targeted to increase to 155 mbbl/d following completion of Phase 2 in 2010. Finally, production levels of 232 mbbl/d are targeted for 2012, following completion of Phase 3 construction. The Company is currently evaluating the opportunity to combine Phase 2 and 3 for a joint operational date of 2011. The project receives the beneﬁ ts of typical mine operations where production is limited only by the facilities and infrastructure – while capturing the generous revenues of oil production with no declines. Sustaining capital will average about $1.22/bbl once the plant is up and running – resulting in signiﬁ cant free cash ﬂ ow. Construction capital costs for Phase 1 of the Horizon Project are estimated at $6.8 billion, including a contingency fund of $700 million, with $1.3 billion spent in 2005, $2.6 billion forecast to be incurred in 2006 and $2.9 billion forecast to be incurred in 2007 and 2008 combined. Total targeted capital costs for all three phases of the development are projected to be $10.8 billion in a US$45/bbl WTI world. The geological risk associated with the project is very low. On this lease, over 16 stratigraphic net wells per section have been drilled to identify overburden levels, and test the ore composition and quality. The result is a well designed mine plan that has been optimized to support the bitumen extraction and processing. To ensure efﬁ cient construction, we have implemented an “80% rule”, with about 80% of the engineering effort required completion prior to major facility construction. This will allow us to ensure materials are available prior to construction and minimize rework. In addition we believe that our execution and labour strategy combined with the ﬂ y-in/ﬂ y-out ability of workers and our ﬁ rst-class camp facilities will position the Horizon Project as “the employer of choice” in the region. At 34º API gravity, low sulphur and fully sweet, the project is designed to produce one of the higher quality SCO products, somewhat reducing marketing risks. Finally, this asset has been designed to accommodate future growth. The large footprint allows for easy access to all parts of the plant and ensures that future production expansions would not impact existing operations. 36 The Assets: Horizon Project RÉAL J.H. DOUCET Senior Vice-President, Oil Sands (cid:21)(cid:156)(cid:192)(cid:136)(cid:226)(cid:156)(cid:152)(cid:202)(cid:42)(cid:192)(cid:156)(cid:141)(cid:105)(cid:86)(cid:204)(cid:202)(cid:86)(cid:213)(cid:147)(cid:213)(cid:143)(cid:62)(cid:204)(cid:136)(cid:219)(cid:105)(cid:202)(cid:42)(cid:133)(cid:62)(cid:195)(cid:105)(cid:202)(cid:163)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:204)(cid:192)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:195)(cid:171)(cid:105)(cid:152)(cid:96)(cid:136)(cid:152)(cid:125) (cid:173)(cid:175)(cid:174) (cid:43)(cid:123)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:43)(cid:206)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:43)(cid:211)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:200) (cid:43)(cid:163)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:211) (cid:163)(cid:211) (cid:21)(cid:156)(cid:192)(cid:136)(cid:226)(cid:156)(cid:152)(cid:202)(cid:42)(cid:192)(cid:156)(cid:141)(cid:105)(cid:86)(cid:204)(cid:202)(cid:42)(cid:133)(cid:62)(cid:195)(cid:105)(cid:202)(cid:163)(cid:202)(cid:86)(cid:156)(cid:152)(cid:195)(cid:204)(cid:192)(cid:213)(cid:86)(cid:204)(cid:136)(cid:156)(cid:152)(cid:202)(cid:171)(cid:192)(cid:156)(cid:125)(cid:192)(cid:105)(cid:195)(cid:195) (cid:173)(cid:175)(cid:174) (cid:43)(cid:123)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:43)(cid:206)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:43)(cid:211)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:200) (cid:43)(cid:163)(cid:201)(cid:211)(cid:228)(cid:228)(cid:120) (cid:211) (cid:163)(cid:206) (cid:163)(cid:153) (cid:163)(cid:153) Site clearing, drainage and deep underground facility installation such as electrical, natural gas, water and sewage were completed during the ﬁ rst half of the year and work on access roads continued throughout the year. Camps for construction workers progressed signiﬁ cantly with the ﬁ rst camp opening in July 2005 and 72% progress on the second camp, essentially on schedule. Ultimately three 2,000 worker camps will be constructed onsite with a fourth employee camp located offsite. To facilitate the Company’s labour strategies, the 737–capable airstrip was completed in September 2005 and now hosts several landings each day. Also on the plant site, coker and extraction separation cell foundations were completed. Erection of the latter was commenced late in the year with 80% of the required material on site. Mine overburden removal progressed 10% ahead of plan, with a total of 6.7 million banked cubic meters of material removed. Earthwork for the raw water and recycle water pond systems commence as scheduled. The Assets: Horizon Project 37 2005 ACTIVITY Phase 1 of the Horizon Project received sanction from the Board of Directors in February 2005 following an extensive front end engineering approach costing over $400 million over a four year period. The high degree of up front project engineering and pre-planning has reduced the risks on “cost-plus” aspects of the project and will mitigate the risk of scope changes on the ﬁ xed price portions (targeted at 68% of Phase 1 costs). The pre-engineering and lessons learned from predecessors have also enabled the Company to prepare a detailed development and logistical plan to reduce the scheduling risk. Signiﬁ cant progress was achieved during 2005 following this sanctioning, with 3-D engineering design models being well advanced in most areas and some plant areas achieving 90% model review stage. In addition, Hazard and Operability reviews were completed with ﬁ ndings being incorporated in plant design. No signiﬁ cant changes occurred during the design. At December 31, 2005, total procurement progress was at C$3.8 billion in awarded contracts and purchase orders, with a further C$600 million in various stages of the tender process. Use of modularization and prefabrication in existing construction yards is considered fundamental to overall success of the project. Module fabrication and assembly maintained schedule and just as importantly, in an environment of key transportation restrictions, module transportation remains on schedule. A total of 88 oversized loads were transported to site by year-end, including piperacks and various reactors. Construction also moved forward in a signiﬁ cant way. During the year several critical path items were completed while on-site safety statistics and performance improved for eleven months in a row and remain well below the Company’s targets as benchmarked against other projects in the area. Horizon Project (continued) WHAT TO EXPECT IN 2006 AND BEYOND Activities continue in 2006 with detailed engineering expected to be essentially complete. In addition, we expect to receive and complete the gas/oil reactor and distillation tower and erect critical path equipment such as the coke drums and extraction separation cells. The main piperack will be substantially completed. In February 2006 the ﬁ rst sections of these piperacks were successfully placed with no rework required. At the ﬁ rst mine pit, construction of the Ore Preparation Plant will commence. The 2006 Phase 1 construction capital budget of $2.6 billion for the Horizon Project will facilitate major work as articulated. This budget represents an acceleration of spending into 2006, which allows Canadian Natural to capitalize on the opportunities created by having signiﬁ cant work completed during 2005. This serves to modify labour requirements timing and ease the execution of the project. Capital for Phase 1 remains at $6.8 billion, and advancing $400 million from 2007 to 2006 will result in construction progress at the end of 2006 targeted at 55%. Expenditures of $128 million to initiate the Engineering Design Speciﬁ cation, order certain Phase 2 long-lead items and review the merits of combining Phase 2 and Phase 3 expansions into one combined Phase targeted to commence production in 2011. While not changing overall expected capital costs, this combination will provide enhanced overall economics as it allows full synergies and production to be achieved at an earlier date. The results of this review, and the decision whether to combine the phases, are expected in early 2007. THE UPSIDE OPPORTUNITY We believe that our land assets, site layout, size, and the manner in which we have planned this Project will facilitate increases in production beyond the 232 mbbl/d of SCO that is currently in development. Our internal estimates of resource potential, based upon our stratigraphic well drilling program accumulate to approximately 6 billion barrels of mineable bitumen throughout our Horizon leases. To this end, we recently articulated an expanded development plan. As noted earlier, we are analyzing the merits of combining Phase 2 and Phase 3 expansions into one combined Phase targeted to commence production in 2011. While not changing overall expected capital costs, this combination will provide enhanced overall economics as it allows full synergies and production to be achieved at an earlier date. This change will also facilitate the Company’s labour strategies in that it provides a smoother transition from Phase 1, keeps an experienced force on-site and optimizes the projected demand for construction labour. Beyond Phases 1 to 3 of the Horizon Project, we will evaluate the Phase 4 addition of 125 mbbl/d of new SCO production targeted to commence in 2015 with Phase 5 adding a further 140 mbbl/d targeted to commence in 2017. In oil sands mining production, the generation of heat is a critical element to success. Engineering design will be completed to consider installation of gasiﬁ cation of the upgrading by-products into Horizon Project Phases 1 to 3 in 2013. This technology would be built into Horizon Project Phase 4 and 5 expansions. 38 The Assets: Horizon Project In announcing these expansions, we were cognizant of the need to maintain discipline while capitalizing on available opportunities. Each of these developments: • Leverages our existing team and experience; • Provides a natural migration of professional engineering and project management skills; • Provides a natural migration of construction workers; • Is ﬁ nancially supported through anticipated cash ﬂ ow of the Company; and, • Helps control operating costs in oil sands mining operations through targeted application of gasiﬁ cation technologies. The Assets: Horizon Project 39 Year-end reserves INDEPENDENT EVALUATION For the year ended December 31, 2005, Canadian Natural retained qualiﬁed independent reserve evaluators, Sproule Associates Limited (“Sproule”) and Ryder Scott Company (“Ryder Scott”) to evaluate 100% of the Company’s conventional proved and probable crude oil, natural gas liquids (“NGL”) and natural gas reserves* and prepare Evaluation Reports on these reserves. Sproule evaluated the Company’s North America conventional assets and Ryder Scott evaluated its international conventional assets. Canadian Natural has been granted an exemption from National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51- 101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This exemption allows the Company to substitute United States Securities and Exchange Commission (“SEC”) requirements for certain disclosures required under NI 51-101. There are two principal differences between the two standards. The ﬁrst is the additional requirement under NI 51-101 to disclose both proved, and proved and probable reserves, as well as the related net present value of future net revenues using forecast prices and costs. The second is in the deﬁnition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), the standards that NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The Company has disclosed proved conventional reserves and the Standardized Measure of discounted future net cash ﬂows using year- end constant prices and costs as mandated by the SEC in the supplementary oil and gas information section of this Annual Report. The Company has elected to provide the net present value (1) of these same conventional proved reserves as well as the conventional proved and probable reserves and the net present value of these reserves under the same parameters as additional voluntary information. For the year ended December 31, 2005, the Company retained a qualiﬁed independent reserves evaluator, GLJ Petroleum Consultants (“GLJ”), to evaluate 100% of Phases 1 through 3 of the Company’s Horizon Oil Sands Project and prepare an Evaluation Report on the Company’s proved and probable oil sands mining reserves incorporating both the mining and upgrading projects. These reserves were evaluated adhering to the requirements of SEC Industry Guide 7 using year-end constant pricing and have been disclosed separately from the Company’s conventional proved and probable crude oil, NGL and natural gas reserves. The Reserve Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of Sproule, Ryder Scott and GLJ to review the qualiﬁcations of and procedures used by each evaluator in determining the estimate of the Company’s quantities and net present value of remaining conventional crude oil, NGL and natural gas reserves as well as the Company’s quantity of oil sands mining reserves. NET CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES During 2005, proved reserve additions of 251 mmboe replaced 145% of production. This growth was achieved at a 2005 ﬁnding and onstream cost of $13.41/boe resulting in a 3 year average ﬁnding and onstream cost of $12.55/boe. Proved and probable reserve additions of 337 mmboe replaced 195% of production at a 2005 and 3 year average ﬁnding and onstream cost of $9.97/boe and $8.05/boe respectively. NORTH AMERICA Proved natural gas reserves increased by 6% to 2.7 tcf and replaced 137% of 2005 production. Similarily, proved crude oil and NGL reserves increased by 7% to 694 mmbbl and replaced 167% of production. The total proved and probable crude oil and NGL reserves increased by 12% to 1,035 mmbbl primarily due to thermal in-situ and Pelican Lake Field developments. INTERNATIONAL North Sea proved reserve additions of 13 mmboe were primarily achieved through waterﬂood design optimization, inﬁll drilling and recompletions. Offshore West Africa proved crude oil and NGL reserves increased by 17% to 134 mmbbl through developments at the Espoir and Baobab ﬁelds in Côte D’Ivoire as well as the acquisition of the Olowi Field in Gabon where 15 mmbbl of proved crude oil and NGL reserves were added. OIL SANDS MINING RESERVES The Horizon Project’s gross proved and probable synthetic crude oil reserves have increased by 88 mmbbl from February 9, 2005 estimates to 2,878 mmbbl due to the incorporation of updated pit limits and mine plans from drilling programs. The reserves are expected to produce over 37 years with ﬁrst production commencing in 2008. * Conventional crude oil, NGL and natural gas includes all of the Company’s light and medium, heavy and, thermal crude oil, natural gas, coal bed methane and natural gas liquid activities. It does not include the Company’s oil sands mining assets. 40 The Assets: Year-End Reserves NET CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES (AFTER ROYALTIES) (2) (3) Crude oil & NGLs (mmbbl) North America North Sea Offshore West Africa Natural gas (bcf) North America North Sea Offshore West Africa Total reserves (mmboe) Reserve replacement ratio (%) (6) Cost to develop ($/boe) (7) 10% discount 15% discount Present value of conventional reserves ($ millions) (1) 10% discount 15% discount December 31, 2005 Proved Proved Developed (4) Undeveloped (4) Proved Total (4) Proved and Probable (5) 402 214 80 696 2,300 16 10 2,326 1,083 0.79 0.67 24,275 20,939 292 76 54 422 441 13 62 516 509 5.69 5.15 6,342 4,881 694 290 134 1,118 2,741 29 72 2,842 1,592 145% 2.36 2.11 1,035 417 206 1,658 3,548 69 110 3,727 2,279 195% 2.55 2.25 30,617 25,820 38,682 31,642 NET CONVENTIONAL CRUDE OIL, NGL AND NATURAL GAS RESERVES (AFTER ROYALTIES) (2) (3) Crude oil & NGLs (mmbbl) North America North Sea Offshore West Africa Natural gas (bcf) North America North Sea Offshore West Africa Total reserves (mmboe) Reserve replacement ratio (%) (6) Cost to develop ($/boe) (7) 10% discount 15% discount Present value of conventional reserves ($ millions) (1) 10% discount 15% discount OIL SANDS MINING RESERVES (2) (8) (9) Bitumen (mmbbl) Synthetic crude oil (mmbbl) December 31, 2004 Proved Proved Developed (4) Undeveloped (4) Proved Total (4) Proved and Probable (5) 367 218 20 605 2,213 12 5 2,230 976 0.85 0.73 13,739 11,838 281 85 95 461 378 15 67 460 538 3.58 3.27 4,399 3,440 648 303 115 1,066 2,591 27 72 2,690 1,514 220% 1.77 1.58 926 415 196 1,537 3,319 57 90 3,466 2,115 281% 1.78 1.56 18,138 15,279 22,937 18,802 December 31, 2005 Gross Reserves Net Reserves Proved Total 2,235 1,833 Proved and Probable 3,430 2,878 Proved Total 1,848 1,626 Proved and Probable 2,848 2,566 The Assets: Year-End Reserves 41 North America North Sea Offshore West Africa 588 17 24 1 36 – (66) 48 648 98 3 – – (3) (70) 18 694 857 20 29 2 49 – (66) 35 926 200 3 – – (4) (70) (20) 1,035 222 – 35 10 38 – (24) 22 303 – 3 – – – (25) 9 290 317 – 49 10 49 – (24) 14 415 – 5 – – – (25) 22 417 85 – – – – – (4) 34 115 – 2 – 15 – (8) 10 134 133 – – – – – (4) 67 196 – 6 – 17 – (8) (5) 206 Total 895 17 59 11 74 – (94) 104 1,066 98 8 – 15 (3) (103) 37 1,118 1,307 20 78 12 98 – (94) 116 1,537 200 14 – 17 (4) (103) (3) 1,658 NET CONVENTIONAL CRUDE OIL AND NGL RESERVES RECONCILIATION (AFTER ROYALTIES) (2) (3) Proved reserves (mmbbl) Reserves, December 31, 2003 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2004 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2005 Proved and probable reserves (mmbbl) Reserves, December 31, 2003 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2004 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2005 42 The Assets: Year-End Reserves NET CONVENTIONAL NATURAL GAS RESERVES RECONCILIATION (AFTER ROYALTIES) (2) (3) Proved reserves (bcf) Reserves, December 31, 2003 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2004 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2005 Proved and probable reserves (bcf) Reserves, December 31, 2003 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2004 Extensions & discoveries Infill drilling Improved recovery Property purchases Property disposals Production Revisions of prior estimates Reserves, December 31, 2005 North America North Sea Offshore West Africa 2,426 334 74 6 182 (8) (383) (40) 2,591 506 22 8 6 (23) (411) 42 2,741 2,919 418 106 6 236 (10) (383) 27 3,319 645 23 14 8 (30) (411) (20) 3,548 62 – – – 10 – (18) (27) 27 – – – – – (7) 9 29 102 – – – 18 – (18) (45) 57 – – – – – (7) 19 69 64 – – – – – (3) 11 72 – – – – – (1) 1 72 72 – – – – – (3) 21 90 – 1 – – – (1) 20 110 Total 2,552 334 74 6 192 (8) (404) (56) 2,690 506 22 8 6 (23) (419) 52 2,842 3,093 418 106 6 254 (10) (404) 3 3,466 645 24 14 8 (30) (419) 19 3,727 The Assets: Year-End Reserves 43 NET CONVENTIONAL FINDING AND ONSTREAM COSTS (AFTER ROYALTIES) (2) (3) Reserve replacement expenditures ($ millions) Reserve additions (mmboe) (10) Proved Proved and probable Finding and onstream costs per boe (11) Proved Proved and probable 2005 3,361 251 337 13.41 9.97 2004 4,259 354 453 12.03 9.40 2003 2,283 185 441 12.34 5.18 Three Year Total 9,903 790 1,231 12.55 8.05 NET CONVENTIONAL RESERVES CLASSIFICATION BY PRODUCT (AFTER ROYALTIES) (2) (3) December 31, 2005 Proved Proved Developed (4) Undeveloped (4) Proved Total (4) Proved and Probable (5) Light crude oil and NGLs North America North Sea Offshore West Africa Total Heavy crude oil North America - Primary Heavy North America - Pelican Lake North America - Thermal Total Total crude oil & NGLs North America North Sea Offshore West Africa Total Natural gas North America North Sea Offshore West Africa Total Total boe 6% 13% 5% 24% 6% 3% 10% 19% 25% 13% 5% 43% 24% – – 24% 67% 1% 5% 3% 9% 1% 2% 15% 18% 19% 5% 3% 27% 5% – 1% 6% 33% 7% 18% 8% 33% 7% 5% 25% 37% 44% 18% 8% 70% 29% – 1% 30% 100% 6% 18% 9% 33% 6% 5% 29% 40% 46% 18% 9% 73% 26% – 1% 27% 100% (1) Net present values of conventional reserves are based upon discounted cash flows prior to the consideration of income taxes and existing asset abandonment liabilities. Only future development costs and associated material well abandonment liabilities have been applied with the exception of Offshore West Africa where all abandonment liabilities have been included. (2) Net reserves mean the Company’s working interest share of gross reserves after consideration of royalties. (3) Reserve estimates and present value calculations are based upon year end constant reference price assumptions as detailed below as well as constant year-end costs. Crude oil & NGLs December 31, 2005 December 31, 2004 December 31, 2003 Natural gas December 31, 2005 December 31, 2004 December 31, 2003 Company Average Price (C$/bbl) WTI @ Cushing Oklahoma (US$/bbl) Hardisty Heavy 12º API (C$/bbl) North Sea Brent (US$/bbl) 46.12 32.14 32.02 Company Average Price (C$/mcf) 9.45 6.44 6.63 61.04 44.04 32.56 Henry Hub Louisiana (US$/mmbtu) 10.08 6.62 5.80 32.64 17.45 26.16 58.21 40.47 30.14 Alberta AECO C (C$/mmbtu) British Columbia Huntingdon Sumas (C$/mmbtu) 9.99 6.78 6.88 9.53 6.94 6.94 (4) (5) A foreign exchange rate of US$0.86/C$1.00 was used in the 2005 evaluation. A foreign exchange rate of US$0.83/C$1.00 was used in the 2004 evaluation. A foreign exchange rate of US$0.77/$C1.00 was used in the 2003 evaluation. Proved reserve estimates and values were evaluated in accordance with the Securities and Exchange Commission (SEC) requirements. The stated reserves have a reasonable certainty of being economically recoverable using year-end prices and costs held constant throughout the productive life of the properties. Proved and probable reserve estimates and values were evaluated in accordance with the standards of the Canadian Oil and Gas Evaluation Handbook (“COGEH”) and as mandated by NI 51-101. The stated reserves have a 50% probability of equaling or exceeding the indicated quantities and were evaluated using year-end costs and prices held constant throughout the productive life of the properties. (6) Reserve replacement ratios were calculated using annual net reserve additions comprised of all change categories divided by the net production for that year. (7) Cost to develop represents total future capital for each reserves category excluding abandonment capital divided by the reserves associated with that category. (8) Synthetic crude oil reserves are based on upgrading of the bitumen reserves. The reserve values shown for bitumen and synthetic crude oil are not additive. (9) Gross reserves mean the total remaining recoverable reserves before consideration of royalties. (10) Reserves additions are comprised of all categories of reserves changes, exclusive of production. (11) Reserves finding and onstream costs are determined by dividing total capital costs for each year excluding cost associated with head office, abandonments, midstream and the Horizon Project by net reserves additions for that year. 44 The Assets: Year-End Reserves Management’s Discussion & Analysis SPECIAL NOTE REGARDING FORWARD- LOOKING STATEMENTS Certain statements in this document or documents incorporated herein by reference for Canadian Natural Resources Limited (the “Company”) may constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. These forward-looking statements can generally be identiﬁed as such because of the context of the statements including words such as “believes”, “anticipates”, “expects”, “plans”, “estimates”, or words of a similar nature. The forward-looking statements are based on current expectations and are subject to known and unknown risks, uncertainties and other factors that may cause the actual results, performance or achievements of the Company, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others: general economic and business conditions which will, among other things, impact demand for and market prices of the Company’s products; foreign currency exchange rates; economic conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or against terrorists or 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 availability and cost of seismic, drilling and other equipment; ability of the Company to complete its capital programs; ability of the Company to transport its products to market; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the ability of the Company to attract the necessary labour required to build its projects; operating hazards and other difﬁculties inherent in the exploration for and production and sale of crude oil and natural gas; availability and cost of ﬁnancing; success of exploration and development activities; timing and success of integrating the business and operations of acquired companies; production levels; uncertainty of reserve estimates; actions by governmental authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); asset retirement obligations; and other circumstances affecting revenues and expenses. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent, and the Company’s course of action would depend upon its assessment of the future considering all information then available. 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. Readers are cautioned that the foregoing list of important factors is not exhaustive. 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 were made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualiﬁed in their entirety by these cautionary statements. Except as required by law, the Company assumes no obligation to update forward-looking statements should circumstances or the Company’s estimates or opinions change. SPECIAL NOTE REGARDING NON-GAAP FINANCIAL MEASURES Management’s discussion and analysis includes references to ﬁnancial measures commonly used in the crude oil and natural gas industry, such as cash ﬂow from operations, adjusted net earnings from operations, and EBITDA (net earnings before interest, taxes, depreciation, depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activities). These ﬁnancial measures are not deﬁned by generally accepted accounting principles (“GAAP”) and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with Canadian GAAP, as an indication of the Company’s performance. MANAGEMENT’S DISCUSSION AND ANALYSIS Management’s discussion and analysis (“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, 2005. The consolidated ﬁnancial statements have been prepared in accordance with Canadian GAAP. A reconciliation of Canadian GAAP to United States GAAP is included in note 15 to the consolidated ﬁnancial statements. All dollar amounts are referenced in Canadian dollars, except where otherwise noted. Common share data has been restated to reﬂect the two-for-one share split in May 2005. The calculation of barrels of oil equivalent (“boe”) is based on a conversion ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of crude oil to estimate relative energy content. This conversion may be misleading, particularly when used in isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. Production volumes are the Company’s interest before royalties, and realized prices exclude the effect of risk management activities, except where noted otherwise. The following discussion and analysis refers primarily to the Company’s 2005 ﬁnancial results compared to 2004 and 2003, unless otherwise indicated. In addition, this discussion details the Company’s capital program and outlook for 2006. This MD&A is dated February 21, 2006. Management’s Discussion & Analysis 45 ABBREVIATIONS Alberta natural gas reference location Annual Information Form barrel barrels per day billion cubic feet billion cubic feet per day barrels of oil equivalent barrels of oil equivalent per day Canadian dollars Floating Production, Storage and Offtake Vessel Greenhouse Gas AECO AIF bbl bbl/d bcf bcf/d boe boe/d C$ FPSO GHG Horizon Project Horizon Oil Sands Project mbbl mbbl/d mboe mboe/d mcf mcf/d mmbbl mmboe mmbtu mmcf/d NGLs NYMEX NYSE SCO SEC TSX UK US US$ WCS WTI thousand barrels thousand barrels per day thousand barrels of oil equivalent thousand barrels of oil equivalent per day thousand cubic feet thousand cubic feet per day million barrels million barrels of oil equivalent million British thermal units million cubic feet per day Natural gas liquids New York Mercantile Exchange New York Stock Exchange Synthetic light crude oil Securities and Exchange Commission Toronto Stock Exchange United Kingdom United States United States dollars Western Canadian Select crude oil blend West Texas Intermediate OBJECTIVE AND STRATEGY The Company’s objective is 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 acquisition of new reserves. The Company accomplishes this objective by having a deﬁned growth and a value enhancement plan for each of its products and segments. The Company takes a balanced approach to growth and investments and focuses on creating long-term shareholder wealth. The Company effectively allocates its capital by maintaining: • Balance among its products, namely natural gas, light crude oil, Pelican Lake crude oil (2), primary heavy crude oil and thermal heavy crude oil; • Balance among near-, mid- and long-term projects; • Balance among acquisitions, exploitation and exploration; Operational discipline and cost control is central to the Company’s strategy. By controlling costs consistently throughout all cycles of the industry, the Company believes that it will achieve continued growth. Cost control is attained by developing area knowledge, by core area domination and by maintaining a high working interest in its properties. The Company is committed to maintaining its strong ﬁnancial position throughout construction of the Horizon Oil Sands Project (“Horizon Project”). The Company believes that it has built the necessary ﬁnancial capacity to complete the Horizon Project while at the same time not compromising delivery from its conventional crude oil and natural gas growth opportunities. Additionally, the Company’s risk management hedge program has been expanded to reduce the risk of volatility in commodity price markets and to support the Company’s cash ﬂow for its capital expenditures program throughout the construction period of the Horizon Project. 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 to selectively acquire properties generating future cash ﬂows in its core regions. These targeted acquisitions provide relatively quick repayment of initial investments and should provide additional free cash ﬂow during the construction years of the Horizon Project while still achieving targeted returns. The year ended December 31, 2005, was another successful year in the execution of the Company’s strategy. Highlights are as follows: • Maintained strong levels of net earnings; • Achieved record levels of adjusted net earnings from operations; • Achieved record levels of cash ﬂow; • Completed the disposition of a large portion of its overriding royalty interests, which were considered non-core to the Company’s operations, for proceeds of approximately $345 million; • Completed the subdivision of its common shares on the basis of two for one; • Increased the quarterly dividend by 20% to $0.06 per and, common share; • Balance between sources of debt and by maintaining a strong balance sheet. (1) Discounted value of conventional crude oil and natural gas reserves and undeveloped land, less net debt. (2) Pelican Lake crude oil is 14-17º API oil, but receives medium quality crude netbacks due to low operating costs and low royalty rates. The Company’s three-phase crude oil marketing strategy includes: • Blending various crude oil streams with diluents into more attractive feedstock; • Supporting and participating in pipeline expansion or new additions; and • Supporting and participating in projects that will increase the conversion capacity of heavy crude oil. • Purchased 850,000 common shares for a total cost of $45 million under the Company’s Normal Course Issuer Bid; • Achieved record levels of natural gas and crude oil and NGLs production; • Achieved its annual production guidance for crude oil and NGLs, and natural gas; • Completed the development of the 57.61% owned and operated Baobab Field offshore Côte d’lvoire West Africa, which commenced production on August 9, 2005 at approximately 30,000 bbl/d net to the Company; • Completed the acquisition of the permit to develop the Olowi Field, offshore Gabon, West Africa with development plans to proceed in 2006; • Received Board of Directors’ approval of the Horizon Project and completed 19% of Phase 1 construction; 46 Management’s Discussion & Analysis • Signed a key pipeline transportation agreement, which will allow Horizon Project Synthetic Crude Oil (“SCO”) to reach the pipeline hub at Edmonton, Alberta; • Completed all major 2005 milestones on the Horizon Project, before winter’ onset; • Commenced steam injection at Primrose North. First oil production began in January 2006 and is expected to increase to 30,000 bbl/d by the third quarter of 2006; • Drilled a record 1,634 net wells, excluding stratigraphic test/service wells; and • Announced a strategy to review the building of a 100% owned and operated upgrader (“Canadian Natural Upgrader”) for the Company’s in-situ oil sands assets in the Cold Lake to Athabasca region. NET EARNINGS AND CASH FLOW FROM OPERATIONS Financial highlights ($ millions, except per common share amounts) Revenue, before royalties Net earnings Per common share – basic (1) – diluted (1) Adjusted net earnings from operations (2) Per common share – basic (1) – diluted (1) Cash flow from operations (3) Per common share – basic (1) – diluted (1) Dividends declared per common share Total assets Total long-term liabilities Capital expenditures, net of dispositions $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2005 10,107 1,050 1.96 1.95 2,034 3.79 3.78 5,021 9.36 9.33 0.236 21,852 9,790 4,932 2004 7,547 1,405 2.62 2.60 1,405 2.62 2.60 3,769 7.03 6.98 0.200 18,372 9,196 4,633 $ $ $ $ $ $ $ $ $ $ $ $ $ $ 2003 6,155 1,403 2.62 2.53 987 1.84 1.80 3,160 5.88 5.76 0.150 14,643 7,277 2,506 $ $ $ $ $ $ $ $ $ $ $ $ $ $ (1) Restated to reflect two-for-one share split in May 2005. (2) Adjusted net earnings from operations is a non-GAAP term 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 following reconciliation lists the after-tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. ($ millions) Net earnings as reported Stock-based compensation, net of tax (a) Unrealized risk management loss (gain), net of tax (b) Unrealized foreign exchange gain, net of tax (c) Effect of statutory tax rate changes on future income tax liabilities (d) Adjusted net earnings from operations $ $ 2005 1,050 481 607 (85) (19) 2,034 $ $ 2004 1,405 168 (27) (75) (66) 1,405 $ $ 2003 1,403 136 – (274) (278) 987 (a) The Company’s employee stock option plan provides for a cash payment option. Accordingly, the intrinsic value of the outstanding vested options is recorded as a liability on the Company’s balance sheet and periodic changes in the intrinsic value, net of taxes, flow through net earnings. (b) Effective January 1, 2004, the Company adopted a new accounting standard whereby financial instruments not designated as hedges are recorded at fair value on its balance sheet, with changes in fair value, net of taxes, flowing through net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil and natural gas. (c) Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates and are immediately recognized in net earnings. (d) All substantively enacted adjustments in applicable income tax rates are applied to underlying assets and liabilities on the Company’s balance sheet in determining future income tax assets and liabilities. The impact of these tax rate changes is recorded in net earnings during the period the legislation is substantively enacted. In 2005, the province of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5%. During 2004, the province of Alberta enacted legislation to reduce its corporate income tax rate by 1%. During 2003 the province of Alberta enacted legislation to reduce its corporate income tax rate by 0.5%. Also during 2003, the Canadian federal government enacted legislation to change the taxation of resource income. The federal legislation reduces the corporate income tax rate on resource income from 28% to 21% over five years beginning January 1, 2003. Over the same period the deduction for resource allowance is being phased out and a deduction of actual crown royalties paid is being phased in. The Company’s future income tax liability was reduced by $31 million with respect to the Alberta corporate income tax rate reduction and by $247 million with respect to the federal resource income tax rate changes. (3) Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Cash flow from operations may not be comparable to similar measures presented by other companies. ($ millions) Net earnings Non-cash items: Depletion, depreciation and amortization Asset retirement obligation accretion Stock-based compensation Unrealized risk management activities Unrealized foreign exchange gain Deferred petroleum revenue tax recovery Future income tax Cash flow from operations $ $ 2005 1,050 2,013 69 723 925 (103) (9) 353 5,021 $ $ 2004 1,405 1,769 51 249 (40) (94) (45) 474 3,769 $ $ 2003 1,403 1,509 62 200 – (343) (9) 338 3,160 Management’s Discussion & Analysis 47 The Company achieved record levels of cash ﬂ ow from operations and production in 2005 as a result of strong operational performance combined with increased commodity prices. The strong operating results are attributable to the Company following its deﬁ ned growth strategy and to the strong asset base the Company has developed over time through organic growth and accretive acquisitions. For the year ended December 31, 2005, the Company recorded net earnings of $1,050 million compared to net earnings of $1,405 million for the year ended December 31, 2004 (2003 – $1,403 million). Net earnings for 2005 include unrealized after-tax expenses of $984 million related to the Company’s risk management activities and stock-based compensation plans, net of foreign exchange gains and the effect of statutory tax rate changes ($nil for 2004; 2003 –unrealized after-tax income of $416 million). Excluding the effects of these items, adjusted net earnings from operations increased 45% to $2,034 million from $1,405 million in 2004 (2003 – $987 million) due to continuing strong crude oil and natural gas prices as well as record levels of total sales on a boe basis, offset by realized risk management activities and the impact of a strengthening Canadian dollar. Cash ﬂ ow from operations reached record levels in 2005. Cash ﬂ ow from operations increased 33% to $5,021 million ($9.36 per common share), up from $3,769 million ($7.03 per common share) in 2004 (2003 – $3,160 million or $5.88 per common share). The increase in cash ﬂ ow from operations was due mainly to strong commodity prices and record levels of total sales volume on a boe basis, offset by realized risk management activities and the impact of a strengthening Canadian dollar. In 2005, the Company’s average sales price per bbl of crude oil and NGLs increased 23% to $46.86 per bbl from $37.99 per bbl in 2004 (2003 – $32.66 per bbl). The Company’s average natural gas price increased 32% to $8.57 per mcf from $6.50 per mcf in 2004 (2003 – $6.21 per mcf). Production volumes before royalties increased 8% to a record 552,960 boe/d, up from 513,835 boe/d in 2004 (2003 – 458,814 boe/d). The increase in production was due to organic growth from the Company’s extensive North America capital expenditure program and the commencement of production from the Baobob Field offshore Côte d’lvoire, as well as the full year impact of accretive acquisitions completed in 2004. Production of crude oil and NGLs before royalties increased 11% to 313,168 bbl/d, up from 282,489 bbl/d in 2004 (2003 – 242,392 bbl/d). Natural gas production before royalties increased 4% to 1,439 mmcf/d, up from 1,388 mmcf/d in 2004 (2003 – 1,299 mmcf/d). Operating highlights Crude oil and NGLs ($/bbl) (1) Sales price (2) Royalties Production expense Netback Natural gas ($/mcf) (1) Sales price (2) Royalties Production expense Netback Barrel of oil equivalent ($/boe) (1) Sales price (2) Royalties Production expense Netback 2005 2004 46.86 3.97 11.17 31.72 8.57 1.75 0.73 6.09 48.77 6.82 8.21 33.74 $ $ $ $ $ $ 37.99 3.16 10.05 24.78 6.50 1.35 0.67 4.48 38.45 5.37 7.35 25.73 $ $ $ $ $ $ (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Including transportation costs and excluding risk management activities. SUMMARY OF QUARTERLY RESULTS The following is a summary of the Company’s quarterly results for the most recently completed quarters: ($ millions, except per common share amounts) 2005 Revenue, before royalties Net earnings (loss) Net earnings (loss) per common share – basic (1) – diluted (1) 2004 Revenue, before royalties Net earnings Net earnings per common share – basic (1) – diluted (1) (1) Restated to reflect two-for-one share split in May 2005. 48 Management’s Discussion & Analysis Total 10,107 1,050 1.96 1.95 Total 7,547 1,405 2.62 2.60 $ $ $ $ $ $ $ $ Dec 31 3,032 1,104 2.06 2.06 Dec 31 1,969 577 1.07 1.06 $ $ $ $ $ $ $ $ Sep 30 2,918 151 0.28 0.28 Sep 30 2,075 311 0.58 0.57 $ $ $ $ $ $ $ $ Jun 30 2,164 219 0.41 0.41 Jun 30 1,865 259 0.48 0.48 $ $ $ $ $ $ $ $ 2003 32.66 2.77 10.28 19.61 6.21 1.32 0.60 4.29 34.84 5.20 7.15 22.49 Mar 31 1,993 (424) (0.79) (0.79) Mar 31 1,638 258 0.49 0.48 $ $ $ $ $ $ $ $ $ $ $ $ $ $ Quarterly revenues have steadily increased throughout 2004 and 2005. This trend reﬂ ects increasing world benchmark crude oil and natural gas prices and increasing sales volumes. • Prices continued to reﬂ ect world-wide economic growth and persistent geopolitical uncertainty, further exacerbated by hurricane activity in the Gulf of Mexico during the third quarters of 2004 and 2005. As a result, the Company’s realized crude oil and NGLs price increased from C$34.21 per bbl for the ﬁ rst quarter of 2004 to C$46.38 per bbl for the fourth quarter of 2005. The realized natural gas price increased from C$6.31 per mcf to C$11.67 per mcf for the same periods. A strengthening Canadian dollar relative to the US dollar offset the impact of increasing commodity prices. The US / Canadian dollar average exchange rate increased from 0.76 for the ﬁ rst quarter of 2004 to 0.84 for the fourth quarter of 2005. • Strong sales volumes in 2005 versus 2004 were also fundamental to the steady increase in revenue, driven by North America’s extensive capital program, the commencement of production from the Baobab Field offshore Côte d’lvoire in 2005, as well as the full year impact of accretive acquisitions completed late in 2004. Daily production increased from 476,944 boe/d day in the ﬁ rst quarter of 2004 to 577,505 boe/d for the fourth quarter of 2005. • The Company acquired certain heavy crude oil properties in its Northern Plains core region in the ﬁ rst quarter of 2004. • The Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest Alberta in the second quarter of 2004. These properties include further ownership in the Ladyfern natural gas ﬁ eld. • The Company acquired certain light crude oil producing properties in the Central North Sea in the third quarter of 2004. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields). • The Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan in the fourth quarter of 2004. In addition to commodity prices, sales volumes and acquisitions, net earnings continued to be impacted by: • The impact of the mark-to-market (“MTM”) treatment of the Company’s commodity price contracts as part of its commodity hedging program. Steadily increasing commodity prices have resulted in signiﬁ cant realized and unrealized risk management losses as the Company strives to lock in prices and secure cash ﬂ ow for its capital expenditure program. • The MTM treatment on its stock-based compensation plan. The Company’s strong stock performance has resulted in the recognition of signiﬁ cant stock-based compensation expense. • Increasing production expense. Higher service costs as a result of increased industry-wide activity in reaction to higher commodity prices as well as the impact of higher crude oil prices on fuel related expenses have resulted in increased costs. • Corporate income tax rates. During the ﬁ rst quarter of 2004, the North America future tax liability was reduced by $66 million as a result of a reduction in the Alberta corporate income tax rate from 12.5% to 11.5%. During the third quarter of 2005, the province of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5% effective July 1, 2005. As a result, the North America future income tax liability was reduced by $19 million. BUSINESS ENVIRONMENT (Yearly average) WTI benchmark price (US$/bbl) (1) Dated Brent benchmark price (US$/bbl) Differential to LLB blend (US$/bbl) Differential to LLB blend as a % of WTI Condensate benchmark price (US$/bbl) NYMEX benchmark price (US$/mmbtu) AECO benchmark price (C$/GJ) US/Canadian dollar average exchange rate (US$) $ $ $ $ $ $ 2005 56.61 54.45 20.83 37% 57.25 8.56 8.05 0.8253 $ $ $ $ $ $ 2004 41.43 38.28 13.44 32% 41.62 6.09 6.43 0.7683 $ $ $ $ $ $ 2003 31.02 28.83 8.55 28% 31.42 5.44 6.35 0.7135 (1) Refers to West Texas Intermediate crude oil barrel prices at Cushing, Oklahoma. World light crude oil prices reached all-time highs in 2005, supported by: • Strong demand growth, particularly in China, India and the United States; • Ongoing geopolitical uncertainties in Iran, Nigeria, Iraq and Venezuela; • Production losses in the Gulf of Mexico from hurricanes Katrina and Rita. Many platforms and reﬁ neries are not expected to be operational until sometime late in 2006; and • Restricted crude oil reﬁ ning capacity, which increased reﬁ ners’ demand for light crude oil to maximize yields of gasoline and distillates. Management’s Discussion & Analysis 49 West Texas Intermediate (“WTI”) averaged US$56.61 per bbl for the year ended December 31, 2005, an increase of 37% compared to US$41.43 per bbl for the year ended December 31, 2004 (2003 – US$31.02 per bbl). Higher WTI pricing is not fully reﬂ ected in the Company’s crude oil price realizations. The positive impact of higher WTI prices on the Company’s crude oil production continues to be mitigated by wider heavy crude oil differentials, which increased 55% to US$20.83 per bbl for the year ended December 31, 2005 from US$13.44 per bbl for the year ended December 31, 2004 (2003 – $US8.55 per bbl). Heavy crude oil differentials in 2005 continued to be higher than the long-term average primarily due to physical limitations for demand at reﬁ neries. Following hurricanes Katrina and Rita, reﬁ ners sought to process lighter barrels to increase their yields of gasoline and distillates, which resulted in the further deterioration of heavy crude oil differentials. Plant turnarounds and maintenance during the year, additional problems at reﬁ neries and upgraders, the higher cost of diluents, and the stronger Canadian dollar also mitigated the effect of higher WTI prices on the Company’s heavy crude oil price realizations. A strengthening in the Canadian dollar reduces the Canadian dollar sales price the Company receives for its crude oil production as crude oil prices are based on US dollar denominated benchmarks. North American natural gas prices also climbed in 2005 due to concerns around supply as well as the impact of higher crude oil prices. NYMEX natural gas prices increased 41% to average US$8.56 per mmbtu for the year ended December 31, 2005, up from US$6.09 per mmbtu for the year ended December 31, 2004 (2003 – $5.44 per mmbtu). AECO natural gas pricing moved directionally with NYMEX, increasing 25% to average $8.05 per GJ for the year ended December 31, 2005, up from $6.43 per GJ for the year ended December 31, 2004 (2003 – $6.35 per GJ). REVENUE, BEFORE ROYALTIES Analysis of changes in revenue, before royalties ($ millions) 2003 Volumes Changes due to Prices Other 2004 Volumes Changes due to Other Prices $ 1,953 3,068 5,021 $ 342 207 549 $ 283 126 409 $ 873 80 953 141 14 155 2,967 3,162 6,129 61 123 5 128 13 (1) 12 478 211 689 – 227 9 236 54 1 55 564 136 700 – – – – – – – – – – – – – 7 $ 2,578 3,401 5,979 1,223 94 1,317 208 14 222 4,009 3,509 7,518 68 $ 170 208 378 $ 546 1,029 1,575 $ 31 (59) (28) 182 (6) 176 383 143 526 – 382 (12) 370 86 1 87 1,014 1,018 2,032 – – – – – – – – – – – – – 9 2005 $ 3,294 4,638 7,932 1,636 23 1,659 476 9 485 5,406 4,670 10,076 77 North America Crude oil and NGLs Natural gas North Sea Crude oil and NGLs Natural gas Offshore West Africa Crude oil and NGLs Natural gas Subtotal Crude oil and NGLs Natural gas Midstream Intersegment eliminations and other (1) Total (35) $ 6,155 – $ 689 – $ 700 (4) 3 (39) $ 7,547 – $ 526 – $ 2,032 $ (7) 2 (46) $ 10,107 $ (1) Eliminates primarily internal transportation and electricity charges. Revenue rose 34% to $10,107 million in 2005, up from $7,547 million in 2004 (2003 – $6,155 million). Price increases accounted for 79% of the 2005 increase (2004 – 51%), while volume increases accounted for the remaining 21% (2004 – 49%). In 2005, 21% of the Company’s crude oil and natural gas revenue was generated outside of North America, up from 20% in 2004 (2003 – 18%). North Sea accounted for 16% of crude oil and natural gas revenue in 2005 and 17% in 2004 (2003 – 16%), and Offshore West Africa accounted for 5% of crude oil and natural gas revenue in 2005 and 3% in 2004 (2003 – 2%). 50 Management’s Discussion & Analysis ANALYSIS OF PRODUCT PRICES (1) Crude oil and NGLs ($/bbl) (2) North America North Sea Offshore West Africa Company average Natural gas ($/mcf) (2) North America North Sea Offshore West Africa Company average Company average ($/boe) (2) Percentage of revenue (excluding midstream revenue) Crude oil and NGLs Natural gas (1) Including transportation costs and excluding risk management activities. (2) Amounts expressed on a per unit basis are based on sales volumes. $ $ $ $ $ $ $ $ $ 2005 2004 2003 $ $ $ $ $ $ $ $ $ 39.62 66.57 59.91 46.86 8.65 3.17 5.91 8.57 48.77 54% 46% $ $ $ $ $ $ $ $ $ 33.16 51.37 49.05 37.99 6.61 3.73 5.25 6.50 38.45 54% 46% 29.40 42.00 36.47 32.66 6.34 3.03 4.37 6.21 34.84 50% 50% Realized crude oil prices increased 23% to average $46.86 per bbl in 2005, up from $37.99 per bbl in 2004 (2003 – $32.66 per bbl). This increase was primarily due to higher benchmark world crude oil prices, as well as an increased proportion of crude oil and NGLs sales coming from Offshore West Africa, offset by higher heavy crude oil differentials and a stronger Canadian dollar. Higher benchmark crude oil prices were primarily driven by increased demand in countries such as China, India and the United States as well as concerns around supply, which increased pricing volatility. The Company’s realized natural gas price increased 32% to average $8.57 per mcf in 2005, up from $6.50 per mcf in 2004 (2003 – $6.21 per mcf), primarily due to supply concerns and a continued strengthening in benchmark North America gas pricing. NORTH AMERICA North America realized crude oil prices increased 19% to average $39.62 per bbl in 2005, up from $33.16 per bbl in 2004 (2003 – $29.40 per bbl). The increase in the realized crude oil price in 2005 was mainly due to higher benchmark crude oil prices, partially offset by wider heavy crude oil differentials and the strengthening Canadian dollar. North America continues to focus on its crude oil marketing strategy, including the development of a blending strategy that expands markets within current pipeline infrastructure, supporting pipeline projects that will provide capacity to transport crude oil to new geographic markets, and working with reﬁ ners to add incremental heavy crude oil conversion capacity. As part of an industry initiative to develop new blends of Western Canadian crude oils, the Company has access to blending capacity of up to 140,000 bbl/d. The Company is currently contributing approximately 139,000 bbl/d of heavy crude oil blends to the Western Canadian Select (“WCS”) stream, a new blend of up to 10 different crude oil streams. WCS resembles a Bow River type crude with distillation cuts approximating a natural heavy crude oil with premium quality asphalt characteristics and has an API of 19°-22°. Volumes of the new blend are expected to grow, with the potential to become a new benchmark for North American markets in addition to WTI. The Company has committed to 25,000 bbl/d of capacity on the Corsicana Pipeline, which will carry crude oil to the Gulf of Mexico and is expected to be in operation late in the ﬁ rst quarter of 2006. The Corsicana Pipeline is made up of a series of segments extending from Patoka Illinois to Nederland Texas, near the US Gulf Coast. North America realized natural gas prices increased 31% to average $8.65 per mcf for the year ended December 31, 2005, up from $6.61 per mcf for the year ended December 31, 2004 (2003 – $6.34 per mcf). This increase was due to supply concerns and ﬂ uctuations in the North America benchmark natural gas price in response to crude oil pricing. A comparison of the price received for the Company’s North America production is as follows: Wellhead price (1)(2) Light crude oil and NGLs (C$/bbl) Pelican Lake crude oil (C$/bbl) Primary heavy crude oil (C$/bbl) Thermal heavy crude oil (C$/bbl) Natural gas (C$/mcf) (1) Including transportation costs and excluding risk management activities. (2) Amounts expressed on a per unit basis are based on sales volumes. 2005 2004 $ $ $ $ $ 58.41 38.39 33.53 32.29 8.65 $ $ $ $ $ 45.90 32.12 28.99 29.00 6.61 $ $ $ $ $ 2003 37.59 28.05 26.21 25.56 6.34 Management’s Discussion & Analysis 51 NORTH SEA North Sea realized crude oil prices increased 30% to average $66.57 per bbl for the year ended December 31, 2005, up from $51.37 per bbl for the year ended December 31, 2004 (2003 – $42.00 per bbl). The increase in the realized crude oil price compared to 2004 was due mainly to higher world benchmark crude oil prices and a narrowing of the average Brent differential, offset by the strengthening Canadian dollar. OFFSHORE WEST AFRICA Offshore West Africa realized crude oil prices increased 22% to average $59.91 per bbl for the year ended December 31, 2005, an increase from $49.05 per bbl for the year ended December 31, 2004 (2003 – $36.47 per bbl). The increase in realized crude oil prices from 2004 was primarily due to higher world benchmark crude oil prices offset by the strengthening Canadian dollar. CRUDE OIL INVENTORY VOLUMES The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place, referred to as “liftings” in this MD&A. For production where revenue has not yet been recognized, the related crude oil inventory volumes, by segment, were as follows at December 31, 2005: (bbl) North America, related to Corsicana pipeline line fill North Sea, related to timing of liftings Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil At December 31, 2004, variances between production volumes and liftings were not signiﬁ cant. ANALYSIS OF DAILY PRODUCTION, BEFORE ROYALTIES 2005 484,157 747,141 412,841 1,644,139 Crude oil and NGLs (bbl/d) North America North Sea Offshore West Africa Natural gas (mmcf/d) North America North Sea Offshore West Africa Total barrel of oil equivalent (boe/d) Product Mix (%) Light crude oil and NGLs Pelican Lake crude oil Primary heavy crude oil Thermal heavy crude oil Natural gas DAILY PRODUCTION, NET OF ROYALTIES Crude oil and NGLs (bbl/d) North America North Sea Offshore West Africa Natural gas (mmcf/d) North America North Sea Offshore West Africa Total barrel of oil equivalent (boe/d) 2005 2004 2003 221,669 68,593 22,906 313,168 1,416 19 4 1,439 552,960 26% 4% 17% 10% 43% 206,225 64,706 11,558 282,489 1,330 50 8 1,388 513,835 24% 4% 19% 8% 45% 174,895 56,869 10,628 242,392 1,245 46 8 1,299 458,814 25% 5% 15% 8% 47% 2005 2004 2003 191,751 68,487 22,293 282,531 1,125 18 4 1,147 473,742 180,011 64,598 11,221 255,830 1,048 50 7 1,105 440,022 152,444 56,928 10,314 219,686 976 46 8 1,030 391,361 Daily production and per barrel statistics are presented throughout this MD&A on a “before royalty” or “gross” basis. Production net of royalties is presented for information purposes only. 52 Management’s Discussion & Analysis The Company’s business approach is to maintain large project inventories and production diversiﬁcation among each of the commodities it produces; namely natural gas, light crude oil and NGLs, Pelican Lake crude oil, primary heavy crude oil and thermal heavy crude oil. Record levels of total crude oil and natural gas production averaged 552,960 boe/d for the year ended December 31, 2005, an increase of 8% or 39,125 boe/d from 513,835 boe/d for the year ended December 31, 2004 (2003 – 458,814 boe/d). The increase in production year over year was due to organic growth from the Company’s extensive North America capital expenditure program and the commencement of production from the Baobab Field offshore Côte d’Ivoire in 2005, as well as the full year impact of accretive acquisitions completed in 2004. Total record crude oil and NGLs production for the year ended December 31, 2005 increased 11% to 313,168 bbl/d from 282,489 bbl/d for the year ended December 31, 2004 (2003 – 242,392 bbl/d). Crude oil and NGLs production for 2005 was in line with the Company’s guidance of 308,000 to 316,000 bbl/d. Natural gas production continues to represent the Company’s largest product offering. Natural gas production for the year ended December 31, 2005 increased 4% or 51 mmcf/d to average 1,439 mmcf/d compared to 1,388 mmcf/d for the year ended December 31, 2004 (2003 – 1,299 mmcf/d). Growth in natural gas production in Western Canada was negatively affected by the early arrival of spring breakup and weather related delays due to unusually wet conditions as well as an overall increase in industry activity. The market for the necessary oilﬁeld services and material has become increasingly competitive, resulting in drilling, completion, tie-in and maintenance delays. Natural gas production for 2005 was in line with the Company’s guidance of 1,436 to 1,448 mmcf/d. The Company expects annual production levels in 2006 to average 1,468 to 1,551 mmcf/d of natural gas and 335,000 to 373,000 bbl/d of crude oil and NGLs. First quarter 2006 production is expected to be between 1,426 and 1,475 mmcf/d of natural gas and 306,000 to 334,000 bbl/d of crude oil and NGLs. NORTH AMERICA North America crude oil and NGLs production for the year ended December 31, 2005 increased 7% or 15,444 bbl/d to average 221,669 bbl/d, up from 206,225 bbl/d for the year ended December 31, 2004 (2003 – 174,895 bbl/d). The increase in crude oil and NGLs production was mainly due to the timing of Primrose production cycles and the positive results of the Pelican Lake waterﬂood project. North America natural gas production for the year ended December 31, 2005 increased 6% or 86 mmcf/d to average 1,416 mmcf/d, up from 1,330 mmcf/d in 2004 (2003 – 1,245 mmcf/d). Natural gas production increased as a result of organic growth and the full year impact of accretive property acquisitions in 2004, but was negatively impacted by the early arrival of spring breakup and weather related delays due to unusually wet conditions during the summer months. In addition to weather related factors, production growth was also negatively impacted by the increased demand for oilﬁeld services and materials, which caused delays in the timing of production being brought on stream. NORTH SEA North Sea crude oil production for the year ended December 31, 2005 was 68,593 bbl/d, an increase of 6% from 64,706 bbl/d for 2004 (2003 – 56,869 bbl/d). Production levels were in line with expectations, reﬂecting anticipated curtailments at the Lyell Field and the Columba B and E Terraces, continued restrictions at Murchison Field due to third party natural gas export facilities and production declines at the satellite Playfair Field. Natural gas production in the North Sea for the year ended December 31, 2005 decreased 62% to average 19 mmcf/d, down from 50 mmcf/d for the year ended December 31, 2004 (2003 – 46 mmcf/d). The decrease in natural gas production was due to the commencement of the natural gas reinjection program in the Banff Field in the Central North Sea late in 2004. The natural gas reinjection project is expected to result in an overall increase in the reservoir recovery, but resulted in reductions in natural gas production in 2005. OFFSHORE WEST AFRICA Offshore West Africa crude oil production for the year ended December 31, 2005 increased 98% to 22,906 bbl/d from 11,558 bbl/d for the year ended December 31, 2004 (2003 – 10,628 bbl/d). The production increase was primarily due to commencement of production from the 57.61% owned and operated Baobab Field in August 2005, as well as increased production from additional inﬁll wells drilled in East Espoir. Management’s Discussion & Analysis 53 ROYALTIES Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore West Africa Company average Natural gas ($/mcf) (1) North America North Sea Offshore West Africa Company average Company average ($/boe) (1) Percentage of revenue (2) Crude oil and NGLs Natural gas Boe $ $ $ $ $ $ $ $ $ 2005 2004 2003 $ $ $ $ $ $ $ $ $ 5.37 0.10 1.62 3.97 1.78 – 0.16 1.75 6.82 8% 20% 14% $ $ $ $ $ $ $ $ $ 4.21 0.08 1.43 3.16 1.40 – 0.15 1.35 5.37 8% 21% 14% 3.79 (0.03) 1.08 2.77 1.38 – 0.13 1.32 5.20 9% 21% 15% (1) Amounts expressed on a per unit basis are based on sales volumes. NORTH AMERICA North America crude oil and NGLs royalties per bbl for the year ended December 31, 2005 increased from 2004 primarily due to higher benchmark crude oil prices, offset by wider heavy crude oil differentials and a strengthening Canadian dollar. Royalty rates are expected to increase in the future as a result of the Primrose South Field payout expected to occur late in 2006 or early 2007. Natural gas royalties increased from 2004 due to higher benchmark natural gas prices, offset by a stronger Canadian dollar and adjustments to royalty rates related to prior years. NORTH SEA North Sea government royalties on crude oil were eliminated effective January 1, 2003. The remaining North Sea royalty represents a gross overriding royalty on the Ninian Field. In 2003, the Company received a refund of royalties previously provided. OFFSHORE WEST AFRICA Offshore West Africa production is governed by the terms of Production Sharing Contracts (“PSCs”). Under the PSCs, revenues are divided into cost recovery revenue and proﬁ t revenue. Cost recovery revenue allows the Company to recover its capital and operating costs and the costs carried by the Company on behalf of the Government State Oil Company. Proﬁ t revenue is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Government. These revenues are reported as sales revenue. The Government’s share of proﬁ t revenue attributable to the Company’s equity interest is allocated to royalty expense and current income tax expense in accordance with the PSCs. Based on current projections, the Espoir Field and the Baobab Field are expected to reach payout in 2007, which will increase royalty rates and current income taxes in accordance with the PSCs. PRODUCTION EXPENSE Crude oil and NGLs ($/bbl) (1) North America North Sea Offshore West Africa Company average Natural gas ($/mcf) (1) North America North Sea Offshore West Africa Company average Company average ($/boe) (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2005 2004 2003 $ $ $ $ $ $ $ $ $ 10.49 14.94 6.50 11.17 0.71 2.44 1.05 0.73 8.21 $ $ $ $ $ $ $ $ $ 8.94 14.03 7.59 10.05 0.62 2.07 1.33 0.67 7.35 $ $ $ $ $ $ $ $ $ 9.14 14.07 8.68 10.28 0.57 1.33 1.39 0.60 7.15 The Company continues to experience increasing production expense in 2006, reﬂ ecting industry cost pressures in all of its operating areas. 54 Management’s Discussion & Analysis NORTH AMERICA North America crude oil and NGLs production expense per bbl for the year ended December 31, 2005 increased by 17% from 2004. The increase was primarily due to higher industry wide service costs, higher fuel related expenses, and a larger portion of the Company’s crude oil volumes being comprised of higher cost thermal crude oil in 2005 versus 2004, offset by the positive impact of higher volumes relative to ﬁ xed costs. North America natural gas production expense per mcf for the year ended December 31, 2005 increased from the comparable periods in 2004. The increase from 2004 was due to the service and commodity cost pressures previously noted, offset by the positive impact of higher volumes relative to ﬁ xed costs. NORTH SEA North Sea crude oil production expense varied on a per barrel basis from 2004 primarily due to the timing of maintenance work, the changes in production volumes on a relatively ﬁ xed cost base, the timing of liftings from various ﬁ elds and the impact of production being diverted from the Kyle Field to the Banff ﬂ oating production storage and offtake vessel (“FPSO”). OFFSHORE WEST AFRICA Offshore West Africa crude oil production expenses are largely ﬁ xed in nature and ﬂ uctuated on a per barrel basis from 2004 due to changes in volumes. Production expenses for the year ended December 31, 2005 compared to 2004 were primarily impacted by the commencement of production from the Baobab Field in August 2005. MIDSTREAM ($ millions) Revenue Production expense Midstream cash flow Depreciation Segment earnings before taxes 2005 2004 2003 77 24 53 8 45 $ $ 68 20 48 7 41 $ $ 61 15 46 7 39 $ $ The Company’s midstream assets consist of three crude oil pipeline systems and a 50% working interest in an 84-megawatt cogeneration plant at Primrose. Approximately 80% of the Company’s heavy crude oil production is transported to international mainline liquid pipelines via the 100% owned and operated ECHO Pipeline, the 62% owned and operated Pelican Lake Pipeline and the 15% owned Cold Lake Pipeline. The midstream pipeline assets allow the Company to control the transport of its own production volumes as well as earn third party revenue. This transportation control enhances the Company’s ability to manage the full range of costs associated with the development and marketing of its heavier crude oil. Earnings and cash ﬂ ow attributable to midstream assets have increased marginally from 2004 primarily due to increased heavy crude oil throughput volumes and increased revenue from the Company’s cogeneration plant. DEPLETION, DEPRECIATION AND AMORTIZATION(1) ($ millions, except per boe amounts) (2) North America North Sea Offshore West Africa Expense $/boe (1) DD&A excludes depreciation on midstream assets. (2) Amounts expressed on a per unit basis are based on sales volumes. 2005 1,595 306 104 2,005 10.02 $ $ $ 2004 1,444 265 53 1,762 9.37 $ $ $ 2003 1,209 252 41 1,502 8.96 $ $ $ Depletion, Depreciation and Amortization (“DD&A”) for the year ended December 31, 2005 increased in total and on a boe basis from 2004. The increase in DD&A was due to higher ﬁ nding and development costs associated with natural gas exploration in North America, the fair value allocation of the acquisition costs associated with acquisitions completed late in 2004, future abandonment costs associated with the acquisition of additional properties in the North Sea, higher estimated future costs to develop the Company’s proved undeveloped reserves in the North Sea and the commencement of production from the Baobab Field in August 2005. ASSET RETIREMENT OBLIGATION ACCRETION ($ millions, except per boe amounts) (1) North America North Sea Offshore West Africa Expense $/boe (1) Amounts expressed on a per unit basis are based on sales volumes. 2005 34 34 1 69 0.34 $ $ $ 2004 28 22 1 51 0.27 $ $ $ 2003 26 36 – 62 0.37 $ $ $ Management’s Discussion & Analysis 55 Accretion expense is the increase in the carrying amount of the asset retirement obligations due to the passage of time. Asset retirement obligation accretion expense for North America increased $6 million or 21% from 2004, primarily due to increased activity in the conventional drilling program and increased requirements under provincial reclamation legislation. Accretion expense for the North Sea increased $12 million or 55% from 2004, largely due to the impact of additional retirement obligations related to property acquisitions completed late in 2004. ADMINISTRATION EXPENSE ($ millions, except per boe amounts) (2) Net expense $/boe (1) Restated to conform to current year presentation. (2) Amounts expressed on a per unit basis are based on sales volumes. 2005 151 0.75 $ $ 2004(1) 125 0.66 $ $ 2003 87 0.52 $ $ Net administration expense for the year ended December 31, 2005 increased in total and on a boe basis from the year ended December 31, 2004 primarily due to higher stafﬁ ng levels associated with the Company’s expanding asset base and costs associated with the Company’s Share Bonus Plan. The Share Bonus Plan incorporates employee share ownership in the Company while reducing the granting of stock options and the dilution of current Shareholders. Under the plan, cash bonuses awarded based on Company and employee performance are subsequently used by a trustee to acquire common shares of the Company. The common shares vest to the employee over a three-year period provided the employee does not leave the employment of the Company. If the employee leaves the employment of the Company, the unvested common shares are forfeited under the terms of the plan. For the year ended December 31, 2005, the Company recognized $17 million of compensation expense under the Share Bonus Plan (December 31, 2004 – $10 million; 2003 – $nil). STOCK-BASED COMPENSATION ($ millions) Stock-based compensation expense 2005 2004 $ 723 $ 249 $ 2003 200 The Company’s Stock Option Plan (the “Option Plan”) provides current employees (the “option holders”) with the right to elect to receive common shares or a direct cash payment in exchange for options surrendered. The design of the Option Plan balances the need for a long-term compensation program to retain employees with the beneﬁ ts of reducing the impact of dilution on current Shareholders and the reporting of the obligations associated with stock options. Transparency of the cost of the Option Plan is increased since changes in the intrinsic value of outstanding stock options are recognized each period. The cash payment feature provides option holders with substantially the same beneﬁ ts and allows them to realize the value of their options through a simpliﬁ ed administration process. The Company recorded a $723 million ($481 million after tax) stock-based compensation expense for the year ended December 31, 2005 in connection with the 125% appreciation in the Company’s share price (December 31, 2005 – C$57.63; December 31, 2004 – C$25.63; December 31, 2003 – C$16.34; December 31, 2002 – C$11.70). As required by GAAP, the Company’s outstanding stock options are valued based on the difference between the exercise price of the stock options and the market price of the Company’s common shares, pursuant to a graded vesting schedule. The liability is revalued quarterly to reﬂ ect changes in the market price of the Company’s common shares and the options exercised or surrendered in the period, with the net change recognized in net earnings, or capitalized during the construction period in the case of the Horizon Project (2005 – $101 million; 2004 – $21 million; 2003 – $10 million). The stock-based compensation liability reﬂ ects the Company’s potential cash liability should all the vested options be surrendered for a cash payout at the market price on December 31, 2005. In periods when substantial stock price changes occur, the Company is subject to signiﬁ cant earnings volatility. For the year ended December 31, 2005, the Company paid $227 million for stock options surrendered for cash settlement (December 31, 2004 – $80 million; 2003 – $31 million). INTEREST EXPENSE ($ millions, except per boe amounts and interest rates) (1) Interest expense $/boe Average effective interest rate (1) Amounts expressed on a per unit basis are based on sales volumes. 56 Management’s Discussion & Analysis $ $ 2005 149 0.74 5.6% $ $ 2004 189 1.01 5.2% $ $ 2003 201 1.20 5.8% Net interest expense decreased on a total and boe basis for the year ended December 31, 2005 from 2004 primarily due to the capitalization of construction period interest related to the Horizon Project in 2005 of $72 million (2004 and 2003 – $nil). Pre- capitalization interest increased from 2004 mainly due to higher interest rates and carrying charges, offset by decreased average debt levels and the impact of the strengthening Canadian dollar, which decreased interest expense attributable to the Company’s US dollar denominated debt securities. RISK MANAGEMENT ACTIVITIES The Company utilizes various derivative ﬁ nancial instruments to manage its commodity price, currency and interest rate exposures. These derivative ﬁ nancial instruments are not used for trading or speculative purposes. Changes in fair value of derivative ﬁ nancial instruments designated as hedges are not recognized in net earnings until such time as the corresponding gains or losses on the related hedged items are also recognized. Changes in fair value of derivative ﬁ nancial instruments not designated as hedges are recognized in the consolidated balance sheets each period with the offset reﬂ ected in risk management activities in the statements of earnings. The Company formally documents all 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 enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash ﬂ ow for capital expenditure programs. Gains or losses on these contracts are included in risk management activities. The Company enters into interest rate swap agreements to manage its ﬁ xed to ﬂ oating 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 amount on which the payments are based. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. Gains or losses on non-designated interest rate contracts are included in risk management activities. Cross currency swap agreements 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. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense. Gains or losses on the termination of derivative ﬁ nancial instruments that have been designated as hedges are deferred under other assets or liabilities on the consolidated balance sheets and amortized into net earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized immediately in net earnings. Gains or losses on the termination of ﬁ nancial instruments that have not been designated as hedges are recognized in net earnings immediately. ($ millions) Realized loss (gain) Crude oil and NGLs financial instruments Natural gas financial instruments Interest rate swaps Unrealized loss (gain) Crude oil and NGLs financial instruments Natural gas financial instruments Interest rate swaps Total 2005 2004 2003 $ $ $ $ $ 753 283 (9) 1,027 847 77 1 925 1,952 $ $ $ $ $ 501 5 (32) 474 (47) – 7 (40) 434 $ $ $ $ $ 95 88 (35) 148 – – – – 148 The realized loss from crude oil and NGLs and natural gas ﬁ nancial instruments decreased the Company’s average realized prices as follows: Crude oil and NGLs ($/bbl) (1) Natural gas ($/mcf) (1) (1) Amounts expressed on a per unit basis are based on sales volumes. 2005 6.68 0.54 $ $ 2004 4.85 0.01 $ $ 2003 1.07 0.19 $ $ Management’s Discussion & Analysis 57 The realized gain on non-designated interest rate swaps would have decreased the Company’s reported interest expense as follows: ($ millions, except interest rates) Interest expense as reported Less: realized risk management gain Average effective interest rate $ $ 2005 149 (9) 140 5.2% $ $ 2004 189 (32) 157 4.4% $ $ 2003 201 (35) 166 4.8% As effective as commodity hedges are against reference commodity prices, a substantial portion of the derivative ﬁ nancial instruments entered into by the Company do not meet the requirements for hedge accounting under GAAP due to currency, product quality and location differentials (the “non-designated hedges”). The Company is required to mark-to-market these non-designated hedges based on prevailing forward commodity prices in effect at the end of each reporting period. Accordingly, unrealized risk management expense reﬂ ects, at the balance sheet date, the implied price differentials for the non-designated hedges for future years. Due to the dramatic increase in crude oil and natural gas forward pricing in 2005, the Company recorded a $925 million ($607 million after tax) unrealized loss on its risk management activities for the year ended December 31, 2005 (2004 – a $40 million gain or $27 million after tax; 2003 – $nil). The cash settlement amount of the risk management ﬁ nancial derivative instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of ﬁ nal settlement of the ﬁ nancial derivative instruments, as compared to their mark-to-market value at December 31, 2005. In addition to the risk management liability recognized on the balance sheet at December 31, 2005, the net unrecognized liability related to the fair value of derivative ﬁ nancial instruments designated as hedges was $990 million (December 31, 2004 – net unrecognized asset of $33 million). Details relating to outstanding derivative ﬁ nancial instruments at December 31, 2005 are disclosed in note 10 to the Company’s audited annual consolidated ﬁ nancial statements as at December 31, 2005. FOREIGN EXCHANGE ($ millions) Realized foreign exchange (gain) loss Unrealized foreign exchange gain Total 2005 (29) (103) (132) $ $ 2004 3 (94) (91) $ $ 2003 8 (343) (335) $ $ The Company’s results are affected by the exchange rates between the Canadian dollar, US dollar, and UK pound sterling. A majority of the Company’s revenue is based on reference to US dollar benchmark prices. An increase in the value of the Canadian dollar in relation to the US dollar results in lower 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 will result in higher revenue from the sale of the Company’s production. Production expenses are also subject to ﬂ uctuations due to changes in the exchange rate of the UK pound sterling to the US dollar related to North Sea operations. 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. In 2005, the majority of the realized foreign exchange gain was the result of the repayment of the Company’s US dollar preferred securities. In addition, net foreign exchange gains were realized on foreign exchange rate ﬂ uctuations on working capital items denominated in US dollars or UK pounds sterling. The unrealized foreign exchange gain is related to the ﬂ uctuation of the Canadian dollar in relation to the US dollar with respect to the US dollar debt and working capital denominated in US dollars or UK pounds sterling. The Canadian dollar ended the year at US$0.8577 compared to US$0.8308 at December 31, 2004 (2003 – US$0.7738). In order to mitigate a portion of the volatility associated with ﬂ uctuations in exchange rates, the Company has designated certain US dollar denominated debt as a hedge against its net investment in US dollar based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment in Shareholders’ equity in the consolidated balance sheets. 58 Management’s Discussion & Analysis TAXES ($ millions, except income tax rates) Taxes other than income tax Current Deferred Total Current income tax North America – Current income tax North America – Large Corporations Tax North Sea Offshore West Africa Other Total Future income tax Effective income tax rate 2005 2004 2003 $ $ $ $ $ 203 (9) 194 82 16 155 32 1 286 353 37.8% $ $ $ $ $ 210 (45) 165 89 11 2 13 1 116 474 29.6% $ $ $ $ $ 116 (9) 107 43 16 23 10 – 92 338 23.5% Taxes other than income tax includes current and deferred petroleum revenue tax (“PRT”) and Canadian provincial capital taxes and surcharges. PRT is charged on certain ﬁ elds in the North Sea at the rate of 50% of net operating income, after allowing for certain deductions including abandonment expenditures. Taxable income from the conventional crude oil and natural gas business in Canada is generated by partnerships, with the related income taxes payable in a subsequent year. North America current income taxes have been provided on the basis of the corporate structure and available income tax deductions and will vary upon the nature and amount of capital expenditures incurred in Canada. The North Sea current income tax expense for 2005 increased from 2004 due mainly to higher realized product prices, increased sales volumes and the deductibility in 2004 of the cost of assets acquired in the UK. In December 2005, the UK government announced plans to double the supplementary charge on proﬁ ts from UK North Sea crude oil and natural gas production to 20%. If enacted, the increased North Sea supplementary charge would increase the Company’s income tax rate in the North Sea from 40% to 50%. The supplementary charge excludes any deduction for ﬁ nancing costs. A charge has not been reﬂ ected in 2005 net earnings as the proposed change has not been substantively enacted. If enacted in 2006, the Company anticipates that this rate change will result in a charge to future income taxes in the amount of $111 million. During 2005, the province of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5% effective July 1, 2005. As a result, the North America future income tax liability was reduced by $19 million. In 2004, the North America future tax liability was reduced by $66 million as a result of a reduction in the Alberta corporate income tax rate from 12.5% to 11.5%. In 2003, the Federal Government enacted legislation to reduce the corporate income tax rate on income from resource activities over a ﬁ ve-year period starting January 1, 2003, bringing the resource industry in line with the general corporate income tax rate. As part of the corporate income tax rate reduction, the legislation also provides for the phased elimination of the existing 25% resource allowance and the introduction of a deduction for actual provincial and other crown royalties paid. The following table shows the effect of non-recurring beneﬁ ts on income taxes: ($ millions, except income tax rates) Income tax as reported Current income tax Future income tax expense Provincial corporate tax rate reductions Federal corporate tax rate reductions Total Expected effective income tax rate before non-recurring benefits 2005 2004 2003 $ $ 286 353 639 19 – 658 39.0% $ $ 116 474 590 66 – 656 32.9% $ $ 92 338 430 31 247 708 38.6% The effective income tax rate for 2005 increased over 2004 due to the effects of the phased elimination of the resource allowance and the phased deductibility of crown royalties. It is anticipated that in 2006, based on budgeted prices and the current availability of tax pools, the Company is expected to be cash taxable in Canada in the amount of $110 million to $170 million. Management’s Discussion & Analysis 59 CAPITAL EXPENDITURES (1) ($ millions) Expenditures on property, plant and equipment Net property acquisitions (2) Land acquisition and retention Seismic evaluations Well drilling, completion and equipping Pipeline and production facilities Total net reserve replacement expenditures Horizon Project: Phase 1 construction costs Capitalized interest and other Total Horizon Project Midstream Abandonments (3) Head office Total net capital expenditures By segment North America North Sea Offshore West Africa Other Horizon Project Midstream Abandonments (3) Head office Total 2005 2004 (320) 254 132 2,000 1,295 3,361 1,329 170 1,499 4 46 22 4,932 2,530 387 439 5 1,499 4 46 22 4,932 $ $ $ $ 1,835 120 89 1,394 821 4,259 – 291 291 16 32 35 4,633 3,355 608 295 1 291 16 32 35 4,633 $ $ $ $ 2003 336 154 77 1,194 522 2,283 – 152 152 11 40 20 2,506 1,769 338 176 – 152 11 40 20 2,506 $ $ $ $ (1) The net capital expenditures do not include non-cash property, plant and equipment additions or disposals. (2) Includes Business Combinations. The 2004 comparative figure includes $26 million in non-cash consideration. (3) 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 diversiﬁ ed asset base that is balanced among various products. In order to facilitate efﬁ cient operations, the Company focuses its activities in core regions where it can dominate the land base and infrastructure. The Company focuses on maintaining its land inventories to enable the continuous exploitation of play types and geological trends, greatly reducing overall exploration risk. By dominating infrastructure, the Company is able to maximize utilization of its production facilities, thereby increasing control over production costs. Net capital expenditures for the year ended December 31, 2005 were $4,932 million compared to $4,633 million for the year ended December 31, 2004 (2003 – $2,506 million). During 2005, the Company continued to make signiﬁ cant progress on its larger, future- growth projects, most notably the Horizon Project, while maintaining its focus on existing assets. The Company drilled a total of 1,882 net wells in 2005 consisting of 890 natural gas wells, 627 crude oil wells, 248 stratigraphic test and service wells, and 117 wells that were dry. This compared to 1,449 net wells drilled in 2004 (2003 – 1,793 net wells). The Company achieved an overall success rate of 93%, excluding stratigraphic test and service wells (2004 and 2003 – 91%). NORTH AMERICA North America accounted for approximately 83% of the total capital expenditures for the year ended December 31, 2005 compared to approximately 80% in 2004 (2003 – 79%). During 2005, the Company drilled 975 net wells targeting natural gas, including 228 wells in Northeast British Columbia, 238 wells in the Northern Plains region, 166 wells in Northwest Alberta, and 343 wells in the Southern Plains region. The Company also drilled 642 net wells targeting crude oil during 2005. The majority of these wells were concentrated in the Company’s crude oil Northern Plains region where 360 heavy crude oil wells, 84 Pelican Lake crude oil wells, 109 thermal crude oil wells, and 7 light crude oil wells were drilled. Another 82 light crude oil wells were drilled during the year in the Company’s other regions. As part of the development of the Company’s heavy crude oil resources, the Company is continuing with its Primrose thermal projects, which includes the Primrose North expansion project and drilling additional wells in the Primrose South project to augment existing production. The Primrose North expansion was substantially completed in 2005 with total capital expenditures of approximately $300 million incurred. Initial steaming commenced in November 2005 and ﬁ rst crude oil production began in January 2006. 60 Management’s Discussion & Analysis In 2004, the Company ﬁled a public disclosure document for regulatory approval of its Primrose East project, a new facility located about 15 kilometers from its existing Primrose South steam plant and 25 kilometers from its Wolf Lake central processing facility. The development application was submitted to the Alberta Energy and Utilities Board in January 2006, with potential impacts associated with the use of bitumen as fuel being evaluated in the Environmental Impact Assessment. The Company expects construction to begin in 2007, with initial steaming scheduled for January 2009. Development at Pelican Lake continued on track in 2005, with 84 wells being drilled and production increasing from approximately 18,000 bbl/d to approximately 28,000 bbl/d over the course of the year. The waterﬂood conversion project is on schedule with production response exceeding expectations. The Company plans to enhance the waterﬂood process through utilization of Polymer Flood technology. A Polymer Flood pilot has been in operation since May 2005 with positive results. The drilling of 150 horizontal wells is planned for 2006. During 2005, the Company sold a large portion of its overriding royalty interests on various producing properties throughout Western Canada and Ontario that were considered non-core to its operations, for proceeds of approximately $345 million, after giving effect to anticipated adjustments. Above average temperatures have continued into 2006. Accordingly, the Company is leveraging its deep drilling inventory and optimizing drilling plans to adjust for road bans and/or site access issues. Despite these challenges the Company still expects to complete the majority of its winter drilling program. However, the risk remains for an early spring breakup which could signiﬁcantly delay tie-ins of many of these new wells. In 2006, the Company’s overall drilling activity in North America is expected to be comprised of approximately 1,139 net natural gas wells and 697 net crude oil wells excluding stratigraphic test/service wells. HORIZON PROJECT On February 9, 2005 the Board of Directors of the Company unanimously approved the Company to proceed with Phase 1 of the Horizon Project. The Horizon Project has continued on schedule and on budget. Speciﬁcally, as at December 31, 2005: • Phase 1 Horizon Project construction was 19% complete; • The detailed engineering work was on schedule, with 3-D engineering models progressing as planned; • The Company awarded $3.8 billion of contracts and purchase orders, with a further $600 million in various stages of the tender process; and • Approximately 1,700 people were on site and functional. Major activities for 2006 will include: • Substantial completion of detailed engineering; • Completion and setting of main piperack modules; • Receiving and erecting of critical equipment; • Beginning construction of ore preparation plant; and • Substantial completion of foundations in each area. First production of light, sweet Synthetic Crude Oil from Phase 1 construction is targeted to commence in the second half of 2008. The Horizon Project is in the early stages of construction. NORTH SEA The Company continued in 2005 with its planned program of inﬁll drilling, recompletions, workovers and waterﬂood optimizations. During 2005, 14 net wells were drilled, consisting of 12 net crude oil wells, 1 net dry well and 1 net service well, with an additional 2.9 net wells drilling at quarter-end. In anticipation of the 2005 program of inﬁll drilling, workovers, and third party business on the T and B Blocks, the Company completed a major refurbishment of the Tiffany platform drilling rig, which is facilitating a two-well program targeting unswept areas of the ﬁeld. The ﬁrst of these two wells was drilled and completed late in 2005. Production from the Kyle Field was diverted to the Banff FPSO during 2005. Under the terms of an early termination agreement, the existing Kyle FPSO was released in September 2005. The consolidation of these production facilities is expected to result in lower combined operating costs from these ﬁelds and may ultimately extend ﬁeld lives for both ﬁelds. Management’s Discussion & Analysis 61 OFFSHORE WEST AFRICA Offshore West Africa capital expenditures include the development of the 57.61% owned and operated Baobab Field, which commenced production on August 9, 2005 at approximately 30,000 bbl/d net to the Company. Upon completion of drilling additional wells in 2006, production levels are expected to achieve approximately 35,000 bbl/d net to the Company. In East Espoir, two of the four inﬁ ll wells scheduled for drilling were completed during 2005, with the remainder expected to be completed in 2006. The drilling of these wells was a result of additional testing and evaluation that revealed a larger quantity of crude oil in place, based upon reservoir studies and production history to date. These new producer wells will effectively exploit this additional potential and could increase the recoverable resources and production. The West Espoir drilling tower, which will facilitate development drilling of the reservoir, is on site and was installed in late 2005. This project is progressing on time and on budget with ﬁ rst crude oil expected in 2006, increasing to approximately 13,000 boe/d once fully developed. The Company purchased a 100% operator interest in the Olowi PSC offshore Gabon in October 2005 and received approval of its development plan for this acquisition subsequent to year end. Development plans include a FPSO handling input from two or three shallow-water producing platforms. Development is expected to begin late in 2006, with ﬁ rst oil expected late in 2008 at a rate of approximately 20,000 bbl/d. LIQUIDITY AND CAPITAL RESOURCES ($ millions, except ratios) Working capital deficit (1) Long-term debt Shareholders’ equity Share capital Retained earnings Foreign currency translation adjustment Total Debt to cash flow (2) Debt to EBITDA (3) Debt to book capitalization (4) Debt to market capitalization After tax return on average common shareholders’ equity (5) After tax return on average capital employed (6) $ $ $ $ $ $ $ $ 2005 1,774 3,321 2,442 5,804 (9) 8,237 0.7x 0.6x 28.7% 9.7% 14.3% 10.4% $ $ $ $ 2004 652 3,538 2,408 4,922 (6) 7,324 1.0x 0.9x 33.8% 21.4% 21.4% 15.3% 2003 505 2,748 2,353 3,650 3 6,006 0.9x 0.8x 32.8% 25.1% 25.6% 17.1% (1) Calculated as current assets less current liabilities. (2) Calculated as current and long-term debt; divided by cash flow from operations for the year. (3) Calculated as current and long-term debt; divided by earnings before interest, taxes, depreciation, depletion and amortization, asset retirement obligation accretion, unrealized foreign exchange, stock-based compensation expense and unrealized risk management activities for the year. (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 net earnings for the year as a percentage of average common shareholders’ equity for the period. (6) Calculated as net earnings plus after-tax interest expense for the year; as a percentage of average capital employed. Average capital employed is the average shareholders’ equity and current and long-term debt for the year. The Company’s capital resources at December 31, 2005 consist primarily of cash ﬂ ow from operations and available credit facilities. Cash ﬂ ow from operations is dependent on factors discussed in the Risks and Uncertainties section of this MD&A. The Company’s ability to renew existing credit facilities and raise new debt is dependent upon these factors, maintaining an investment grade debt rating and the condition of capital and credit markets. Management believes internally generated cash ﬂ ows supported by the implementation of the Company’s hedge policy, the ﬂ exibility of its capital expenditure programs supported by its ﬁ ve and ten year ﬁ nancial plans, the Company’s existing credit facilities and the Company’s ability to raise new debt, will be sufﬁ cient to sustain its operations and support its growth strategy. At December 31, 2005 the Company had undrawn bank lines of credit of $3,285 million. These credit lines are supported by credit facilities, which if not extended, mature in 2008, 2009 and 2010. At December 31, 2005, the Company’s working capital deﬁ cit was $1,774 million and included the current portion of other long- term liabilities of $1,471 million, comprised of stock-based compensation of $629 million and the mark-to-market valuation of non-designated risk management ﬁ nancial derivative instruments of $842 million. The settlement of the stock-based compensation liability is dependant upon both the surrender of vested stock options for cash settlement by employees and the value of the Company’s share price at the time of surrender. The cash settlement amount of the risk management ﬁ nancial derivative instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of ﬁ nal settlement of the ﬁ nancial derivative instruments, as compared to their mark-to-market value at December 31, 2005. The Company is committed to maintaining a strong ﬁ nancial position. In 2005, strong operational results and high commodity prices resulted in debt to book capitalization levels of 28.7%. The Company believes it has the necessary ﬁ nancial capacity to complete the 62 Management’s Discussion & Analysis Horizon Project while at the same time not compromising delivery of conventional crude oil and natural gas growth opportunities. The ﬁnancing of Phase 1 of the Horizon Project development is guided by the competing principles of retaining as much direct ownership interest as possible while maintaining a strong balance sheet. Existing proved development projects, which have largely been funded prior to December 31, 2005, such as Baobab, Primrose North and West Espoir should provide identiﬁed growth in production volumes in 2006 through 2008, and are expected to generate incremental free cash ﬂows during this period. In January 2005, the Board of Directors authorized the expansion of the Company’s commodity hedging program to reduce the risk of volatility in commodity price markets and to underpin the Company’s cash ﬂow for its capital expenditures program through the Horizon Project construction period. This expanded program allows for the hedging of up to 75% of the near 12 months budgeted production, up to 50% of the following 13 to 24 months estimated production and up to 25% of production expected in months 25 to 48 through the use of derivative ﬁnancial instruments. For the purpose of this program, the purchase of crude oil put options is in addition to the above parameters. As a result, approximately 75% of budgeted 2006 crude oil volumes have been hedged through the use of collars. Approximately 60% of budgeted 2006 natural gas volumes have similarly been hedged through the use of collars. In addition, for 2007, put options have been acquired on 200,000 bbl/d at an average ﬂoor price of US$47.50 and a further 100,000 bbl/d at an average ﬂoor price of US$28.00. The Company has not hedged any production volumes beyond 2007. The Company continues to evaluate the need for further hedging in 2007 and beyond, given continuing capital requirements for Horizon and other capital projects. LONG-TERM DEBT Long-term debt at December 31, 2005 amounted to $3,321 million. The debt to EBITDA ratio decreased to 0.6x and the debt to book capitalization decreased to 28.7% compared to a debt to EBITDA ratio of 0.9x and a debt to book capitalization of 33.8% in 2004. These ratios are currently below the Company’s guidelines for balance sheet management of debt to EBITDA of 1.5x to 2.0x and debt to book capitalization of 35% to 45%. OPERATING FACILITIES As at December 31, 2005 the Company had in place unsecured syndicated bank credit facilities of $3,425 million, comprised of: • a $100 million operating demand facility; • a two-tranche revolving credit and term loan facility of $1,825 million; and • a 5-year revolving and term loan facility of $1,500 million. The ﬁrst $1,000 million tranche of the $1,825 million facility is fully revolving for a period of three years to June 2008. The second tranche of $825 million is fully revolving for a period of ﬁve years to June 2010. Both tranches are extendible annually for one-year periods at the mutual agreement of the Company and the lenders. If not extended, the full amount of the outstanding principal would be repayable at the end of year two following the initiation of the term period. The $1,500 million revolving credit and term loan facility has a ﬁve-year term, with three, one-year extension provisions. If the facility is not extended, the amount outstanding would be repayable in December 2009. These facilities provide that the borrowings may be made by way of operating advances, prime loans, bankers’ acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank’s prime rates or at money market rates plus applicable margins. The weighted average interest rate of the bank credit facilities outstanding at December 31, 2005, was 5.44% (2004 – 3.47%). The Company also has an unsecured £15 million demand overdraft credit facility for the Company’s North Sea operations. At December 31, 2005 there were no amounts drawn on this facility. In addition to the outstanding debt, as at December 31, 2005 letters of credit aggregating $24 million have been issued. MEDIUM-TERM NOTES In May 2005, the Company issued $400 million of debt securities maturing June 2015, bearing interest at 4.95%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. In May 2004, the Company repaid the $125 million 6.85% unsecured debentures due May 2004, which were issued under a previous medium-term note program. In January 2006, the Company issued $400 million of debt securities maturing January 2013, bearing interest at 4.50%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. After issuing these securities, the Company has $1.6 billion remaining on its $2 billion shelf prospectus ﬁled in August 2005 that allows for the issue of medium-term notes in Canada until September 2007. If issued, these securities will bear interest as determined at the date of issuance. Management’s Discussion & Analysis 63 SENIOR UNSECURED NOTES In December 2005, the Company repaid the US$125 million 7.69% senior unsecured notes. The 6.42% senior unsecured notes were repaid in May 2004. The adjustable rate senior unsecured notes bear interest at 6.54% and have annual principal repayments of US$31 million commencing in May 2007, through May 2009. PREFERRED SECURITIES In September 2005, the Company redeemed the US$80 million 8.30% preferred securities due May 25, 2011 for cash consideration of US$91 million, including an early repayment premium of US$11 million as required under the Note Purchase Agreement. US DOLLAR DEBT SECURITIES In June 2005, the Company ﬁled a short form shelf prospectus that allows for the issue of up to US$2 billion of debt securities in the United States until July 2007. If issued, these securities will bear interest as determined at the date of issuance. In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. The Company has entered into interest rate swap contracts to convert the ﬁxed rate interest coupon into a ﬂoating interest rate on the securities due December 2014. The ratings of the Company’s debt securities and its relationships with principal banks are important to the Company as it continues to expand and grow. Hence, it is the Company’s management intention to maintain a strong balance sheet and ﬁnancial position. The Company’s debt securities are rated “Baa1” with a stable outlook by Moody’s Investor Services Inc., “BBB+” by Standard & Poors Corporation (“S&P”) and “BBB(high)” with a stable trend by Dominion Bond Rating Services Limited. S&P assigns a rating outlook to the Company and not to the individual debt intruments. S&P has assigned a negative outlook to the Company. SHARE CAPITAL Shareholders of the Company approved a subdivision or share split of its issued and outstanding common shares on a two-for-one basis at the Company’s Annual and Special Meeting held on May 5, 2005. As at December 31, 2005, there were 536,348,000 common shares outstanding. As at February 21, 2006, the Company had 537,156,000 common shares outstanding. In January 2005, the Company renewed its Normal Course Issuer Bid allowing it to purchase up to 26,818,012 common shares or 5% of the Company’s outstanding common shares on the date of announcement, during the 12-month period beginning January 24, 2005 and ending January 23, 2006. As at December 31, 2005, the Company had purchased 850,000 common shares at an average price of $53.29 per common share for a total cost of $45 million. In January 2006, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock Exchange and the New York Stock Exchange to purchase up to 26,852,545 common shares or 5% of the outstanding common shares of the Company on the date of the announcement, during the 12-month period beginning January 24, 2006 and ending January 23, 2007. As at February 21, 2006, the Company had not purchased any additional shares under the Normal Course Issuer Bid. In February 2005, the Board of Directors approved an increase in the annual dividend paid by the Company to $0.225 per common share. In May 2005, the Board of Directors approved an increase in the annual dividend paid by the Company to $0.24 per common share. In February 2004, the Board of Directors increased the annual dividend paid by the Company to $0.20 per common share, up from the previous level of $0.15 per common share. In February 2006, the Company’s Board of Directors approved an increase in the annual dividend paid by the Company to $0.30 per common share for 2006. The increase represents a 27% increase from the prior year, recognizes the stability of the Company’s cash ﬂow, and provides a return to Shareholders. This is the sixth consecutive year in which the Company has paid dividends and the ﬁfth consecutive year of an increase in the distribution paid to its Shareholders. 64 Management’s Discussion & Analysis COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS In the normal course of business, the Company has entered into various contractual arrangements and commitments that will have an impact on the Company’s future operations. These contractual obligations and commitments primarily relate to debt repayments, operating leases relating to ofﬁce space and offshore production and storage vessels, and ﬁrm commitments for gathering, processing and transmission services, as well as expenditures relating to asset retirement obligations. The Company has not entered into any contracts that would require consolidation under CICA Accounting Handbook, AcG-15, Consolidation of Variable Interest Entities. The following table summarizes the Company’s commitments as at December 31, 2005: ($ millions) 2006 2007 2008 2009 2010 Thereafter Product transportation and pipeline (1) Offshore equipment operating lease Offshore drilling Asset retirement obligations (2) Long-term debt (3) Other (4) $ $ $ $ $ $ 195 51 132 82 – 61 $ $ $ $ $ $ 133 51 100 4 161 62 $ $ $ $ $ $ 148 52 35 4 36 21 $ $ $ $ $ $ 94 51 – 4 36 29 $ $ $ $ $ $ 85 51 – 7 – 23 $ $ $ $ $ $ 1,111 180 – 3,224 2,966 8 (1) During the year, the Company entered into a 25 year pipeline transportation agreement commencing in 2008, related to future crude oil production. The agreement is renewable for successive 10-year periods at the Company’s option. During the initial term, annual toll payments before operating costs will be approximately $35 million. (2) Represents management’s estimate of the future payments to settle asset retirement obligations related to resource properties, facilities, production platforms and gathering systems, based on current legislation and industry operating practices. (3) No debt repayments are reflected for the bank credit facilities due to the extendable nature of the facilities. (4) Consists of future expenditures related primarily to office lease, electricity and crude oil processing. The Board of Directors has approved the construction costs for Phase 1 of the Horizon Project, which are budgeted to be $6.8 billion, including a contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and 2008. The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The Company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated ﬁnancial position. RESERVES For the year ended December 31, 2005, the Company retained qualiﬁed independent reserve evaluators, Sproule Associates Limited (“Sproule”) and Ryder Scott Company (“Ryder Scott”) to evaluate 100% of the Company’s conventional proved and probable crude oil, natural gas liquids (“NGL”) and natural gas reserves (1) and prepare Evaluation Reports on these reserves. Sproule evaluated the Company’s North America conventional assets and Ryder Scott evaluated its international conventional assets. The Company has been granted an exemption from National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada. This exemption allows the Company to substitute United States Securities and Exchange Commission (“SEC”) requirements for certain disclosures required under NI 51-101. There are two principal differences between the two standards. The ﬁrst is the additional requirement under NI 51-101 to disclose both proved, and proved and probable reserves, as well as the related net present value of future net revenues using forecast prices and costs. The second is in the deﬁnition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook (“COGEH”), the standards that NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. The Company has disclosed proved conventional reserves and the Standardized Measure of discounted future net cash ﬂows using year-end constant prices and costs as mandated by the SEC in the supplementary oil and gas information section of this Annual Report. The Company has elected to provide the net present value (2) of these same conventional proved reserves as well as the conventional proved and probable reserves and the net present value of these reserves under the same parameters as additional voluntary information. The Company has also elected to provide both proved, and proved and probable conventional reserves and the net present value of these reserves using forecast prices and costs as voluntary additional information, which is disclosed in the Company’s most recent Annual Information Form. Reserves and net present values presented for years prior to 2003 were evaluated in accordance with the standards of National Policy 2-B which has now been replaced by NI 51-101. The stated reserves were reasonably evaluated as economically productive using year-end costs and prices escalated at appropriate rates throughout the productive life of the properties. For the year ended December 31, 2005, the Company retained a qualiﬁed independent reserves evaluator, GLJ Petroleum Consultants (“GLJ”), to evaluate 100% of Phases 1 through 3 of the Company’s Horizon Project and prepare an Evaluation Report on the Company’s proved and probable oil sands mining reserves incorporating both the mining and upgrading projects. These reserves were evaluated adhering to the requirements of SEC Industry Guide 7 using year-end constant pricing and have been disclosed separately from the Company’s conventional proved and probable crude oil, NGL and natural gas reserves. Management’s Discussion & Analysis 65 The Reserve Committee of the Company’s Board of Directors has met with and carried out independent due diligence procedures with each of Sproule, Ryder Scott and GLJ to review the qualiﬁcations of and procedures used by each evaluator in determining the estimate of the Company’s quantities and net present value of remaining conventional crude oil, NGL and natural gas reserves as well as the Company’s quantity of oil sands mining reserves. Additional reserve disclosure is contained in the supplementary oil and gas information of this Annual Report and the Company’s most recent Annual Information Form. (1) Conventional crude oil, NGL and natural gas includes all of the Company’s light and medium, heavy, and thermal crude oil, natural gas, coal bed methane and natural gas liquid activities. It does not include the Company’s oil sands mining assets. (2) Net present values of conventional reserves are based upon discounted cash flows prior to the consideration of income taxes and existing asset abandonment liabilities. Only future development costs and associated material well abandonment liabilities have been applied with the exception of Offshore West Africa where all abandonment liabilities have been included. RISKS AND UNCERTAINTIES The Company is exposed to various operational risks inherent in exploring, developing, producing and marketing crude oil and natural gas and the mining and upgrading of bitumen. These inherent risks include, but are not limited to, the following items: • Economic risk of ﬁnding and producing reserves at a reasonable cost, including the risk of reserve revisions due to economic and technical factors. Reserve revisions can have a positive or negative impact on asset valuations and depletion rates. • Pricing risk of marketing reserves at an acceptable price given current market conditions. • 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. • Credit risk related to non-payment for sales contracts or non-performance by counterparties to contracts. • Interest rate risk associated with the Company’s ability to secure ﬁnancing at commercially acceptable terms. • Foreign exchange risk due to ﬂuctuating exchange rates, as the majority of sales are based in US dollars. • Environmental impact risk associated with exploration and development activities. • Risk of catastrophic loss due to ﬁre, explosion or acts of nature. • Other risks associated with changing governmental policies, social instability and other political, economic or diplomatic developments in the Company’s international operations. The Company uses a variety of means to help minimize these risks. The Company maintains a comprehensive insurance program to reduce risk to an acceptable level and to protect it against signiﬁcant losses. Operational control is enhanced by focusing efforts on large core regions with high working interests and by assuming operatorship of all key facilities. Product mix is diversiﬁed, ranging from the production of natural gas to the production of crude oil of various grades. The Company believes this diversiﬁcation reduces price risk when compared with over-leverage to one commodity. Sales of crude oil and natural gas are aimed at various markets to ensure that undue exposure to any one market does not exist. Financial instruments are utilized to help ensure targets are met and to manage commodity prices, foreign currency rates and interest rate exposure. The Company minimizes credit risks by entering into sales contracts and ﬁnancial derivatives with only highly rated entities and ﬁnancial institutions. The arrangements and policies concerning the Company’s ﬁnancial instruments are under constant review and may change depending upon the prevailing market conditions. Refer to the “Risk management activities” section of this MD&A. In addition, the Company reviews 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. The Company’s capital structure mix is also monitored on a continual basis to ensure that it optimizes ﬂexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. For additional detail regarding the Company’s risks and uncertainties, refer to the Company’s most recent Annual Information Form. 66 Management’s Discussion & Analysis ENVIRONMENT The Company continues to employ an Environmental Management Plan (the “Plan”) to ensure the welfare of its employees, the communities in which it operates, and the environment as a whole. Environmental protection is of fundamental importance and is undertaken in accordance with guiding principles approved by the Company’s Board of Directors. A detailed copy of the Company’s Plan is presented to, and reviewed by, the Board of Directors annually. The Plan is updated quarterly at the Directors’ meetings. The Company’s environmental management plan and operating guidelines focus on minimizing the impact of ﬁ eld operations while meeting regulatory requirements and corporate standards. The Company, as part of this plan, has implemented a proactive program that includes: • An annual 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 reduction and conservation program; and • A program to replace the majority of fresh water for steaming with brackish water. The Company has also established stringent operating standards in four areas: • Using water-based, environmentally friendly drilling muds whenever possible; • Implementing cost effective ways of reducing greenhouse natural gas emissions per unit of production; • Exercising care with respect to all waste produced through effective waste management plans; and • Minimizing produced water volumes onshore and offshore through cost-effective measures. In 2005, the Company’s capital expenditures included $46 million for abandonment expenditures, an increase from $32 million in 2004 (2003 – $40 million). Estimated asset retirement obligation, undiscounted ($ millions) North America North Sea Offshore West Africa North Sea PRT recovery 2005 2,050 1,185 90 3,325 (370) 2,955 $ $ 2004 1,770 1,265 25 3,060 (600) 2,460 $ $ The estimate of the future site restoration liability is based on estimates of future costs to abandon and restore the wells, production facilities and offshore production platforms. There are numerous factors that affect these costs including such things as the number of wells drilled, well depth and the speciﬁ c environmental legislation. The estimated costs are based on engineering estimates using current costs and technology in accordance with present legislation and industry operating practice. The future abandonment costs to be incurred by the Company in the North Sea will result in an estimated recovery of PRT of $370 million (2004 – $600 million, 2003 – $330 million), as abandonment costs are an allowable deduction in determining PRT and may be carried back to reclaim PRT previously paid. The PRT recovery reduces the net abandonment liability of the Company to $2,955 million (2004 – $2,460 million, 2003 – $1,950 million). The North Sea PRT recovery has decreased substantially from 2004 primarily due to improved economics related to the various ﬁ elds, including a higher pricing environment and stronger Canadian dollar at December 31, 2005. Under these economic conditions, end of ﬁ eld losses at Tiffany previously assumed to be available for relief against PRT due from other ﬁ elds is signiﬁ cantly reduced. The Company’s strategy in the North Sea consists of developing commercial hubs around its core operated properties with the goal of increasing production, lowering costs and extending the economic lives of its production facilities, thereby delaying the eventual abandonment dates. KYOTO PROTOCOL In December 2002, the Canadian Federal Government ratiﬁ ed the Kyoto Protocol (“Kyoto”). The Company continues to work with the Federal and Provincial governments on the regulatory framework for greenhouse gases for larger emitters. The framework under development would see harmonized regulation between the two levels of government. Both levels of government have indicated that existing legislation will be amended in 2006 to create further requirements for reporting emissions, facility-based emission intensity targets and regulatory compliance. Compliance with emission intensity targets is expected for 2008, which is the ﬁ rst year of the compliance period for the Kyoto Protocol. Management’s Discussion & Analysis 67 The Company will continue to develop strategies that will enable it to deal with the risks and opportunities associated with new climate change policies. In addition, the Company will work with relevant parties to ensure that new policies encourage innovation, energy efﬁciency, targeted research and development while not impacting Canada’s competitive position. Due to the high degree of cost uncertainty when the Federal Government ratiﬁed Kyoto, maximum per tonne cost assurances were agreed with large emitters for 2008 – 2012. Beyond 2012 investment concerns were addressed by the Federal Government as outlined in eight principles that would guide its negotiations and policies for this later stage. CRITICAL ACCOUNTING ESTIMATES The preparation of ﬁnancial statements requires the Company to make judgements, assumptions and estimates in the application of generally accepted accounting principles that have a signiﬁcant impact on the Company’s ﬁnancial position and operations. Actual results could differ from those estimates, and those differences could be material. Critical accounting estimates are reviewed by the Company’s Audit Committee annually. The Company believes the following are the most critical accounting estimates in preparing its consolidated ﬁnancial statements. PROPERTY, PLANT AND EQUIPMENT/DEPLETION, DEPRECIATION AND AMORTIZATION The Company follows the full cost method of accounting for its conventional crude oil and natural gas properties and equipment. Accordingly, all costs relating to the exploration for and development of conventional crude oil and natural gas reserves, whether successful or not, are capitalized and accumulated in country-by-country cost centres. Proceeds on disposal of properties are ordinarily deducted from such costs without recognition of proﬁt or loss except where such disposal constitutes a signiﬁcant portion of the Company’s reserves in that country. Under Canadian GAAP, the capitalized costs and future capital costs related to each cost centre from which there is production are depleted on the unit-of-production method based on the estimated proved reserves of that country using estimated future prices and costs, rather than constant dollar pricing as required by the SEC. The carrying amount of crude oil and natural gas properties in each cost centre may not exceed their recoverable amount (“the ceiling test”). The recoverable amount is calculated as the undiscounted cash ﬂow using proved reserves and estimated future prices and costs. If the carrying amount of a cost centre exceeds its recoverable amount, an impairment loss equal to the amount by which the carrying amount of the properties exceeds their estimated fair value is charged against net earnings. Fair value is calculated as the cash ﬂow from those properties using proved and probable reserves and estimated future prices and costs, discounted at a risk-free interest rate. The alternate acceptable method of accounting for crude oil and natural gas properties and equipment is the successful efforts method. A major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical exploration costs would be charged against net earnings in the year incurred rather than being capitalized to property, plant and equipment. In addition, under this method cost centres are deﬁned based on reserve pools rather than by country. The use of the full cost method usually results in higher capitalized costs and higher DD&A rates compared to the successful efforts method. CRUDE OIL AND NATURAL GAS RESERVES The Company retains qualiﬁed independent reserves evaluators to evaluate the Company’s proved and probable crude oil and natural gas reserves. In 2005, 100% of the Company’s reserves were evaluated by qualiﬁed independent reserves evaluators. The estimation of reserves involves the exercise of judgement. Forecasts are based on engineering data, future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. The Company expects that over time its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels. 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 reserve estimate would result in a higher or lower DD&A charge to net earnings. Downward revisions to reserve estimates could also result in a write-down of crude oil and natural gas property, plant and equipment carrying amounts under the ceiling test. ASSET RETIREMENT OBLIGATION Under CICA Handbook Section 3110, Asset Retirement Obligations (“ARO”), the Company is required to recognize a liability for the future retirement obligations associated with the Company’s property, plant and equipment. An ARO is recognized to the extent of a legal obligation associated with the retirement of a tangible long-lived asset the Company is required to settle as a result of an existing or enacted law, statute, ordinance or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are speciﬁc to the sites involved, there are many individual assumptions underlying the Company’s total ARO amount. These individual assumptions can be subject to change based on experience. 68 Management’s Discussion & Analysis The estimated fair values of asset retirement obligations related to long-term assets are recognized as a liability in the period in which they are incurred. Retirement costs equal to the estimated fair value of the asset retirement obligations are capitalized as part of the cost of associated capital assets and are amortized to expense through depletion over the life of the asset. The fair value of the asset retirement obligation is estimated by discounting the expected future cash ﬂows to settle the asset retirement obligation at the Company’s average credit-adjusted risk-free interest rate of 6.8%. In subsequent periods, the asset retirement obligation is adjusted for the passage of time and for any changes in the amount or timing of the underlying future cash ﬂows. The estimates described impact earnings by way of depletion on the capital cost and accretion on the asset retirement liability. In addition, differences between actual and estimated costs to settle the asset retirement obligation, timing of cash ﬂows to settle the obligation and future inﬂation rates could result in gains or losses on the ﬁnal settlement of the asset retirement obligations. An ARO is not recognized for assets with an indeterminate useful life (e.g. pipeline assets) because an amount cannot be reasonably estimated. An ARO for these assets will be recorded in the ﬁrst period in which the lives of these assets are determinable. RISK MANAGEMENT ACTIVITIES The Company utilizes various instruments to manage its commodity price and foreign currency exposures on revenue, and interest rate exposures on US dollar denominated debt. These derivative and ﬁnancial instruments are not used for trading or speculative purposes. On January 1, 2004, the Company prospectively adopted the Canadian Institute of Chartered Accountants’ (“CICA”) Accounting Guideline (“AcG”) 13, “Hedging Relationships” and Emerging Issues Committee (“EIC”) 128, “Accounting for Trading, Speculative or Non-Hedging Derivative Financial instruments”. Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded on the consolidated balance sheet as either an asset or liability with changes in fair value recognized in net earnings. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indications. The cash settlement amount of the risk management ﬁnancial derivative instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of ﬁnal settlement of the ﬁnancial derivative instruments, as compared to their mark-to-market value at December 31, 2005. PURCHASE PRICE ALLOCATIONS The costs of corporate and asset acquisitions are allocated to the acquired assets and liabilities based on their estimated fair value at the time of acquisition. The determination of fair value requires the Company to make assumptions and estimates regarding future events. The allocation process is inherently subjective and impacts the amount assigned to individually identiﬁable assets and liabilities. As a result, the purchase price allocation impacts the Company’s reported assets and liabilities and future net earnings due to the impact on future DD&A expense and impairment tests. The Company has made various assumptions in determining the fair values of the acquired assets and liabilities. The most signiﬁcant assumptions and judgments made relate to the estimation of the fair value of the crude oil and natural gas properties. To determine the fair value of these properties, the Company estimates (a) crude oil and natural gas reserves, and (b) future prices of crude oil and natural gas. Reserve estimates are based on the work performed by the Company’s engineers and outside consultants. The judgments 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 future price forecasts amongst 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. CONTROL ENVIRONMENT Based on their evaluation as of December 31, 2005, the Company’s President and the Chief Financial Ofﬁcer concluded, pursuant to Canadian Multilateral Instrument 52-109 Part 2.1, that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Company in its annual ﬁlings is recorded, processed, summarized and reported within the time periods that meet the regulatory requirements. In addition, as of December 31, 2005, there were no changes in the Company’s internal controls over ﬁnancial reporting that occurred during 2005 that have materially affected, or are reasonably likely to materially affect its internal controls over ﬁnancial reporting. The Company will continue to periodically evaluate its disclosure controls and procedures and internal controls over ﬁnancial reporting and will make any modiﬁcations from time to time as deemed necessary. Management’s Discussion & Analysis 69 NEW ACCOUNTING STANDARDS In January 2005, the CICA issued four new standards relating to the recognition, measurement and disclosure of ﬁnancial instruments. • Section 3855 – “Financial Instruments – Recognition and Measurement” prescribes when a ﬁnancial asset, ﬁnancial liability, or non-ﬁnancial derivative is to be recognized on the balance sheet as well as its measurement amount. This Section also speciﬁes how ﬁnancial instruments gains and losses are to be presented. Transitional provisions for this Section vary based on the type of ﬁnancial instruments under consideration. • Section 3865 – “Hedges” expands on existing AcG 13 – “Hedging Relationships”, and Section 1650 “Foreign Currency Translation”, by specifying how hedge accounting is to be applied and what disclosures are necessary when it is applied. Retroactive application of this Section is not permitted. • Section 1530 – “Comprehensive Income” introduces new standards for reporting and disclosure of comprehensive income. Comprehensive income is the change in equity (net assets) of the Company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Financial statements of prior periods are required to be restated only for non-ﬁnancial instrument items. • Section 3251 – “Equity” replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes in equity during a reporting period. Financial statements of prior periods are required to be restated only for non-ﬁnancial instrument items. For all other items, comparative ﬁnancial statements presented are not restated, but an adjustment to the opening balance of accumulated other comprehensive income may be required. The Company plans to adopt these new standards effective January 1, 2007. The effect on the Company’s consolidated ﬁnancial statements cannot be reasonably determined at this time as the ﬁnancial derivatives outstanding at December 31, 2006 and their related fair values are not known. 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 high shareholder returns. Annual budgets are developed, scrutinized throughout the year and changed if necessary in the context of project returns, product pricing expectations, and balance in project risk and time horizons. The Company maintains a high ownership level and operatorship level in all of its properties and can therefore control the nature, timing and extent of capital expenditures in each of its project areas. The Company expects production levels in 2006 to average 1,468 mmcf/d to 1,551 mmcf/d of natural gas and 335,000 bbl/d to 373,000 bbl/d of crude oil and NGLs. The budgeted capital expenditures in 2006 are currently expected to be as follows: 2006 Budget $ $ 1,741 1,097 733 187 63 3,821 2,561 222 128 30 6,762 ($ millions) North America natural gas North America crude oil and NGLs North Sea Offshore West Africa Property acquisitions, dispositions and midstream Horizon Project Phase 1 Construction Capitalized interest and other items Horizon Project Phases 2/3 engineering Canadian Natural Upgrader engineering Total 70 Management’s Discussion & Analysis NORTH AMERICA NATURAL GAS The 2006 North American natural gas program will be as follows: (number of wells) Northeast British Columbia Northwest Alberta Northern Plains Southern Plains Total 2006 Budget 262 147 251 479 1,139 Drilling will comprise both deep and conventional targets, with new production growth coming from the Company’s Northeast British Columbia and Northwest Alberta areas. NORTH AMERICA CRUDE OIL AND NGLS The 2006 North America crude oil drilling program is highlighted by continued development of Primrose North thermal production and another strong conventional heavy program, as follows: (number of wells) Conventional heavy crude oil Thermal heavy crude oil Light crude oil Pelican Lake crude oil Total 2006 Budget 344 92 111 150 697 The Company continues the disciplined development of its heavy crude oil resources. Conventional heavy crude oil drilling is expected to increase, reﬂecting favourable crude oil prices and new opportunities identiﬁed in the property acquisitions made during 2004. Due to the nature of heavy crude oil production patterns, where production volumes ramp up during the ﬁrst months of production, much of the production resulting from the expanded drill program will not be realized until late 2007. In 2006, the Company expects to continue its Primrose thermal crude oil expansion plans. Activity in 2006 will be focused on the Primrose South expansion. Production from this project is subject to the cycling of steam injection and crude oil production and is expected to remain at similar levels to the 2005 production. The waterﬂood conversion project is on schedule with production response exceeding expectations. The Polymer Flood pilot project has yielded positive results to date and will continue in 2006. THE HORIZON PROJECT The Horizon Project is designed as a phased development and includes two components: the mining of bitumen and an onsite upgrader. Phase 1 production is expected to commence in the second half of 2008 at 110,000 bbl/d of 34° API light, sweet synthetic crude oil (“SCO”). The phased approach provides the Company with improved cost and project controls including labour and materials management, and directionally mitigates the effects of growth on local infrastructure. Construction costs for Phase 1 of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million, with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and 2008. Extensive front end design and the high degree of project deﬁnition have enabled the Company to obtain approximately 68% of Phase 1 costs on a ﬁxed price basis. The high degree of up front project engineering and pre-planning is expected to reduce the risks associated with scope changes. NORTH SEA The capital budget in 2006 for the North Sea is $733 million and includes the drilling of approximately 12 net platform wells on Ninian, Murchison and Tiffany. The Company will also conduct a mobile drilling program for which 6 subsea producer wells will be drilled at Columba E, Lyell, Toni and Thelma. Average crude oil production is expected to increase from 2005 production levels; however, natural gas volumes are expected to be ﬂat as natural gas production at the Banff Field is diverted to reinjection. OFFSHORE WEST AFRICA In 2006, the capital budget for Offshore West Africa is set at $187 million, of which the Company anticipates $79 million to be spent on completing inﬁll drilling at East Espoir and developing the West Espoir Field. West Espoir development is expected to yield ﬁrst oil by mid-2006 at approximately 13,000 boe/d. Two additional wells will be completed at Baobab in 2006, allowing production to ramp to approximately 35,000 bbl/d net to the Company. $32 million will be expended on development of the Olowi Field offshore Gabon in 2006, with ﬁrst oil expected late in 2008. Management’s Discussion & Analysis 71 SENSITIVITY ANALYSIS (1) The following table is indicative of the annualized sensitivities of cash ﬂ ow 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 2005. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. Price changes Crude oil – WTI US$1.00/bbl (2) Excluding financial derivatives Including financial derivatives Natural gas – AECO C$0.10/mcf (2) Excluding financial derivatives Including financial derivatives Volume changes Crude oil – 10,000 bbl/d Natural gas – 10 mmcf/d Foreign currency rate change $0.01 change in C$ in relation to US$ (2) Interest rate change – 1% Cash flow from Cash flow from operations ($/share, basic) operations ($ millions) Net earnings ($ millions) Net earnings ($/share, basic) $ $ $ $ $ $ $ $ 113 60 38 14 104 32 $ $ $ $ $ $ 0.21 0.11 0.07 0.03 0.19 0.06 82-84 7 $ 0.15-0.16 0.01 $ $ $ $ $ $ $ $ $ 79 40 24 8 53 17 32-33 7 $ $ $ $ $ $ $ $ 0.15 0.07 0.05 0.01 0.10 0.03 0.06 0.01 (1) The sensitivities are calculated based on 2005 fourth quarter results excluding mark-to-market gains (losses) on risk management activities. (2) For details of financial instruments in place, refer to note 10 to the Company’s audited annual consolidated financial statements as at December 31, 2005. DAILY PRODUCTION BY SEGMENT, BEFORE ROYALTIES (1) Q1 Q2 Q3 Q4 2005 2004 2003 Crude oil and NGLs (bbl/d) North America North Sea Offshore West Africa Total Natural gas (mmcf/d) North America North Sea Offshore West Africa Total Barrels of oil equivalent (boe/d) North America North Sea Offshore West Africa Total 209,125 71,139 7,539 287,803 1,430 23 2 1,455 447,446 74,956 7,914 530,316 215,693 62,884 10,487 289,064 1,434 17 3 1,454 454,602 65,751 11,027 531,380 231,260 73,543 29,921 334,724 1,400 18 5 1,423 464,607 76,545 30,759 571,911 230,263 66,798 43,207 340,268 1,402 15 6 1,423 463,869 69,361 44,275 577,505 221,669 68,593 22,906 313,168 1,416 19 4 1,439 457,695 71,651 23,614 552,960 206,225 64,706 11,558 282,489 1,330 50 8 1,388 427,936 73,093 12,806 513,835 174,895 56,869 10,628 242,392 1,245 46 8 1,299 382,315 64,469 12,030 458,814 (1) The Company recognizes revenue on its crude oil production when title transfers to the customer and delivery has taken place. For production where revenue has not yet been recognized, the related crude oil inventory volumes, by segment, were as follows at December 31, 2005: (bbls) North America, related to Corsicana pipeline line fill North Sea, related to timing of liftings Offshore West Africa, related to timing of liftings, net of government entitlement to profit oil At December 31, 2004, variances between production volumes and liftings were not signiﬁ cant. 2005 484,157 747,141 412,841 1,644,139 72 Management’s Discussion & Analysis PER UNIT RESULTS (1) Q1 Q2 Q3 Q4 2005 2004 $ Crude oil and NGLs ($/bbl) Sales price (2) $ Royalties Production expense Netback Natural gas ($/mcf) Sales price (2) Royalties Production expense Netback Barrels of oil equivalent ($/boe) Sales price (2) Royalties Production expense Netback $ $ $ $ 39.81 3.39 11.30 25.12 6.68 1.30 0.69 4.69 39.94 5.42 8.04 26.48 $ $ $ $ $ $ 42.51 3.33 11.66 27.52 7.33 1.48 0.71 5.14 43.05 5.85 8.29 28.91 $ $ $ $ $ $ 57.35 5.11 11.48 40.76 8.61 1.93 0.76 5.92 54.87 7.84 8.56 38.47 $ $ $ $ $ $ 46.38 3.89 10.33 32.16 11.67 2.30 0.76 8.61 56.08 8.01 7.93 40.14 (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Including transportation costs and excluding risk management activities. NETBACK ANALYSIS ($/boe) (1) Sales price (2) Royalties Production expense (3) Netback Midstream contribution (3) Administration (4) Interest, net Realized risk management activities loss Realized foreign exchange (gain) loss Taxes other than income tax – current Current income tax – North America Current income tax – Large Corporations Tax Current income tax – North Sea Current income tax – Offshore West Africa Current income tax – other Cash flow (1) Amounts expressed on a per unit basis are based on sales volumes. (2) Including transportation costs and excluding risk management activities. (3) Excluding inter-segment eliminations. (4) Restated to conform to current year presentation. TRADING AND SHARE STATISTICS $ $ $ $ $ $ $ $ 46.86 3.97 11.17 31.72 8.57 1.75 0.73 6.09 48.77 6.82 8.21 33.74 2005 48.77 6.82 8.21 33.74 (0.26) 0.75 0.74 5.13 (0.15) 1.01 0.41 0.08 0.77 0.17 0.01 25.08 $ $ $ $ $ $ $ $ 37.99 3.16 10.05 24.78 6.50 1.35 0.67 4.48 38.45 5.37 7.35 25.73 2004 38.45 5.37 7.35 25.73 (0.26) 0.66 1.01 2.52 0.02 1.12 0.47 0.05 0.01 0.07 0.01 20.05 $ $ $ $ $ $ $ $ 2003 32.66 2.77 10.28 19.61 6.21 1.32 0.60 4.29 34.84 5.20 7.15 22.49 2003 34.84 5.20 7.15 22.49 (0.28) 0.52 1.20 1.09 0.05 0.69 0.14 0.06 0.26 0.09 – 18.67 Q1 Q2 Q3 Q4 2005 Total 2004 Total (1) $ $ $ TSX – C$ Trading volume (thousands) Share price ($/share) High Low Close Market capitalization at December 31 ($ millions) Shares outstanding (thousands) NYSE – US$ Trading volume (thousands) Share price ($/share) High Low Close Market capitalization at December 31 ($ millions) Shares outstanding (thousands) $ $ $ 169,018 37.38 24.28 34.18 48,333 30.37 19.74 28.41 (1) Restated to reflect two-for-one share split in May 2005. 155,274 160,121 153,579 637,992 606,024 $ $ $ $ $ $ 46.98 30.54 44.40 $ $ $ 60.00 45.52 52.50 $ $ $ 62.00 43.55 57.63 $ $ $ $ 62.00 24.28 57.63 30,910 536,348 $ $ $ $ 27.58 15.96 25.63 13,744 536,361 68,743 66,802 67,676 251,554 125,468 38.03 24.49 36.38 $ $ $ 50.73 36.87 45.19 $ $ $ 54.05 36.65 49.62 $ $ $ $ 54.05 19.74 49.62 26,614 536,348 $ $ $ $ 22.37 11.94 21.39 11,470 536,361 Management’s Discussion & Analysis 73 Management’s Report The accompanying consolidated ﬁnancial statements and all information in the annual report are the responsibility of management. The consolidated ﬁnancial statements have been prepared by management in accordance with the accounting policies in the notes to the consolidated ﬁnancial statements. Where necessary, management has made informed judgements and estimates in accounting for transactions that were not complete at the balance sheet date. In the opinion of management, the ﬁnancial statements have been prepared in accordance with Canadian generally accepted accounting principles appropriate in the circumstances. The ﬁnancial information 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, 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 examine the consolidated ﬁnancial statements in accordance with generally accepted auditing standards in Canada and provide an independent professional opinion. 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. This committee, which is comprised of non- management directors, meets with management and the external 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 & Chief Operating Ofﬁcer February 21, 2006 Auditors’ Report Douglas A. Proll CA Senior Vice President, Finance & Chief Financial Ofﬁcer Randall S. Davis CA Vice President, Financial Accounting & Controls TO THE SHAREHOLDERS OF CANADIAN NATURAL RESOURCES LIMITED, We have audited the consolidated balance sheets of Canadian Natural Resources Limited as at December 31, 2005 and 2004 and the consolidated statements of earnings, retained earnings and cash ﬂows for each of the years in the three year period ended December 31, 2005. These consolidated ﬁnancial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these ﬁnancial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the ﬁnancial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the ﬁnancial statements. An audit also includes assessing the accounting principles used and signiﬁcant estimates made by management, as well as evaluating the overall ﬁnancial statement presentation. In our opinion, these consolidated ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the Company as at December 31, 2005 and 2004 and the results of its operations and its cash ﬂows for each of the years in the three year period ended December 31, 2005 in accordance with Canadian generally accepted accounting principles. Chartered Accountants Calgary, Alberta, Canada February 21, 2006 COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company’s consolidated ﬁnancial statements, such as the change described in Note 10 to the consolidated ﬁnancial statements. Our report to the shareholders dated February 21, 2006 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors’ report when the change is properly accounted for and adequately disclosed in the consolidated ﬁnancial statements. Chartered Accountants Calgary, Alberta, Canada February 21, 2006 74 Management and Auditors’ Reports Consolidated Balance Sheets As at December 31 (millions of Canadian dollars) ASSETS Current assets Cash and cash equivalents Accounts receivable and other Future income tax (note 6) Current portion of other long-term assets (note 2) Property, plant and equipment (note 3) Other long-term assets (note 2) LIABILITIES Current liabilities Accounts payable Accrued liabilities Current portion of long-term debt (note 4) Current portion of other long-term liabilities (note 5) Long-term debt (note 4) Other long-term liabilities (note 5) Future income tax (note 6) SHAREHOLDERS’ EQUITY Share capital (note 7) Retained earnings Foreign currency translation adjustment (note 8) Commitments (note 11) Approved by the Board of Directors: Catherine M. Best Chair of the Audit Committee and Director N. Murray Edwards Vice-Chairman of the Board of Directors and Director 2005 2004 18 1,546 487 – 2,051 19,694 107 21,852 573 1,781 – 1,471 3,825 3,321 1,434 5,035 13,615 2,442 5,804 (9) 8,237 21,852 $ $ $ $ 28 1,055 83 34 1,200 17,064 108 18,372 379 1,019 194 260 1,852 3,538 1,208 4,450 11,048 2,408 4,922 (6) 7,324 18,372 $ $ $ $ Consolidated Financial Statements 75 Consolidated Statements of Earnings For the years ended December 31 (millions of Canadian dollars, except per common share amounts) Revenue Less: royalties Revenue, net of royalties Expenses Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion (note 5) Administration Stock-based compensation (note 5) Interest, net Risk management activities (note 10) Foreign exchange gain Earnings before taxes Taxes other than income tax (note 6) Current income tax (note 6) Future income tax (note 6) Net earnings Net earnings per common share (note 9) Basic Diluted $ 2005 10,107 (1,366) 8,741 $ 2004 7,547 (1,011) 6,536 $ 1,663 270 2,013 69 151 723 149 1,952 (132) 6,858 1,883 194 286 353 1,050 1.96 1.95 $ $ $ 1,400 250 1,769 51 125 249 189 434 (91) 4,376 2,160 165 116 474 1,405 2.62 2.60 $ $ $ $ $ $ 2003 6,155 (872) 5,283 1,209 262 1,509 62 87 200 201 148 (335) 3,343 1,940 107 92 338 1,403 2.62 2.53 Consolidated Statements of Retained Earnings For the years ended December 31 (millions of Canadian dollars) Balance – beginning of year Net earnings Dividends on common shares (note 7) Purchase of common shares under Normal Course Issuer Bid (note 7) Balance – end of year 2005 4,922 1,050 (127) (41) 5,804 $ $ 2004 3,650 1,405 (107) (26) 4,922 $ $ 2003 2,424 1,403 (81) (96) 3,650 $ $ 76 Consolidated Financial Statements 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 Asset retirement obligation accretion Stock-based compensation Unrealized risk management activities Unrealized foreign exchange gain Deferred petroleum revenue tax recovery Future income tax Deferred charges Abandonment expenditures Net change in non-cash working capital (note 12) Financing activities (Repayment) issue of bank credit facilities Issue (repayment) of medium-term notes Repayment of senior unsecured notes Repayment of preferred securities Issue of US dollar debt securities Repayment of obligations under capital leases Dividends on common shares Issue of common shares on exercise of stock options Purchase of common shares Net change in non-cash working capital (note 12) Investing activities Expenditures on property, plant and equipment Net proceeds on sale of property, plant and equipment Net expenditures on property, plant and equipment Net proceeds on sale of other assets Net change in non-cash working capital (note 12) (Decrease) increase in cash Cash – beginning of year Cash – end of year Supplemental disclosure of cash flow information (note 12) 2005 2004 2003 $ 1,050 $ 1,405 $ 1,403 2,013 69 723 925 (103) (9) 353 (31) (46) (147) 4,797 (435) 400 (194) (107) – – (121) 9 (45) 19 (474) (5,340) 454 (4,886) 11 542 (4,333) (10) 28 18 $ 1,769 51 249 (40) (94) (45) 474 (33) (32) (14) 3,690 357 (125) (54) – 830 (7) (101) 24 (33) 6 897 (4,582) 7 (4,575) – (88) (4,663) (76) 104 28 $ 1,509 62 200 – (343) (9) 338 10 (40) (48) 3,082 (647) – (85) – – (8) (77) 89 (144) (11) (883) (2,486) 20 (2,466) – 341 (2,125) 74 30 104 $ Consolidated Financial Statements 77 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 head-quartered in Calgary, Alberta, Canada. The Company’s operations are focused in North America, largely in western Canada, the United Kingdom portion of the North Sea and Offshore West Africa. Within western Canada, the Company is developing its Horizon Oil Sands Project (the “Horizon Project”) and maintains its midstream activities. The Horizon Project involves a plan to recover bitumen through mining operations, while the midstream activities include the Company’s pipeline operations and an electricity co-generation system. The consolidated ﬁnancial statements of the Company have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”). A summary of differences between accounting principles in Canada and those generally accepted in the United States (“US GAAP”) is contained in note 15. Signiﬁcant accounting policies are summarized as follows: (A) PRINCIPLES OF CONSOLIDATION The consolidated ﬁnancial statements include the accounts of the Company and all of its subsidiaries and partnerships. A signiﬁcant portion of the Company’s activities are conducted jointly with others and the consolidated ﬁnancial statements reﬂect only the Company’s proportionate interest in such activities. (B) MEASUREMENT UNCERTAINTY Management has made estimates and assumptions regarding certain assets, liabilities, revenues and expenses in the preparation of the consolidated ﬁnancial statements. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated ﬁnancial statements. Accordingly, actual results may differ from estimated amounts. Depletion, depreciation and amortization, and amounts used for ceiling test calculations are based on estimates of crude oil and natural gas reserves and commodity prices, production expenses and capital costs required to develop and produce those reserves. Substantially all of the Company’s reserve estimates are evaluated annually by independent engineering ﬁrms. By their nature, estimates of reserves and the related future cash ﬂows are subject to measurement uncertainty, and the impact of differences between actual and estimated amounts on the consolidated ﬁnancial statements of future periods could be material. The calculation of asset retirement obligations includes estimates of the future costs to settle the asset retirement obligation, the timing of the cash ﬂows to settle the obligation, and the future inﬂation rates. The impact of differences between actual and estimated costs, timing and inﬂation on the consolidated ﬁnancial statements of future periods could be material. The measurement of petroleum revenue tax expense and the related provision in the consolidated ﬁnancial statements are subject to uncertainty associated with future recoverability of crude oil and natural gas reserves, commodity prices and the timing of future events, which could result in material changes to deferred amounts. (C) CASH AND CASH EQUIVALENTS Cash comprises cash on hand and demand deposits. Other investments (term deposits and certiﬁcates of deposit) with an original term to maturity of three months or less are reported as cash equivalents on the balance sheet. (D) PROPERTY, PLANT AND EQUIPMENT The Company follows the full cost method of accounting for crude oil and natural gas properties and equipment as prescribed by the Canadian Institute of Chartered Accountants (“CICA”). Accordingly, all costs relating to the exploration for and development of crude oil and natural gas reserves are capitalized and accumulated in country-by-country cost centres. Administrative overhead incurred during the development phase of large capital projects is capitalized until the projects are available for their intended use. Proceeds on disposal of properties are ordinarily deducted from such costs without recognition of proﬁt or loss except where such disposal constitutes a signiﬁcant portion of the Company’s reserves in that country. Contractual arrangements that meet the deﬁnition of a lease as speciﬁed in Emerging Issues Committee (“EIC”) 150 – “Determining Whether an Arrangement Contains a Lease” are accounted for as capital leases or operating leases as appropriate. 78 Notes to the Consolidated Financial Statements For mining activities, property acquisition, construction and development costs are capitalized. The Company reviews the recoverability of the carrying amount of its mining properties when events or circumstances indicate that the carrying amounts may not be recoverable. (E) DEPLETION, DEPRECIATION AND AMORTIZATION Costs related to each cost centre are depleted on the unit-of-production method based on the estimated proved reserves of that country. Volumes of net production and net reserves before royalties are converted to equivalent units on the basis of estimated relative energy content. In determining its depletion base, the Company includes estimated future costs to be incurred in developing proved reserves and excludes the cost of unproved properties and major development projects. Unproved properties are assessed periodically to determine whether impairment has occurred. When proved reserves are assigned or the value of unproved property is considered to be impaired, the cost of the unproved property or the amount of the impairment is added to costs subject to depletion. Certain costs for major development projects are not subject to depletion until the projects are available for their intended uses. Processing and production facilities are depreciated on a straight-line basis over their estimated lives. The Company reviews the carrying amount of its crude oil and natural gas properties (“the properties”) relative to their recoverable amount (“the ceiling test”) for each cost centre at each annual balance sheet date, or more frequently if circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash ﬂow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized in depletion equal to the amount by which the carrying amount of the properties exceeds their fair value. Fair value is calculated as the cash ﬂow from those properties using proved and probable reserves and expected future prices and costs, discounted at a risk-free interest rate. Midstream assets are depreciated on a straight-line basis over their estimated lives. The Company reviews the recoverability of the carrying amount of the midstream assets when events or circumstances indicate that the carrying amount might not be recoverable. If the carrying amount of the midstream assets exceeds their recoverable amount, an impairment loss equal to the amount by which the carrying amount of the midstream assets exceeds their fair value is recognized in depreciation. Head ofﬁce capital assets are amortized on a declining balance basis over their estimated useful lives. (F) CAPITALIZED INTEREST Beginning in 2005, following the Board of Directors’ approval of the Horizon Project, the Company commenced capitalization of construction period interest based on costs incurred and the Company’s cost of borrowing. Interest capitalization will cease once construction is substantially complete and the Horizon Project is available for its intended use. (G) DEFERRED CHARGES Deferred charges primarily include deferred ﬁnancing costs associated with the issuance of long-term debt and settlement costs of long-term natural gas contracts. Deferred charges are amortized over the original term of the related instrument. (H) ASSET RETIREMENT OBLIGATIONS The Company provides for future asset retirement obligations on its resource properties, facilities, production platforms and gathering system based on current legislation and industry operating practices. The fair values of asset retirement obligations related to property, plant and equipment are recognized as a liability in the period in which they are incurred. Retirement costs equal to the fair value of the asset retirement obligations are capitalized as part of the cost of the associated property, plant and equipment and are amortized to expense through depletion and depreciation over the life of the asset. The fair value of an asset retirement obligation is estimated by discounting the expected future cash ﬂows to settle the asset retirement obligation at the Company’s average credit-adjusted risk-free interest rate. In subsequent periods, the asset retirement obligation is adjusted for the passage of time and for changes in the amount or timing of the underlying future cash ﬂows. Actual expenditures are charged against the accumulated asset retirement obligation as incurred. (I) FOREIGN CURRENCY TRANSLATION Foreign operations that are self-sustaining are translated using the current rate method. Under this method, assets and liabilities are translated to Canadian dollars from their functional currency using the exchange rate in effect at the consolidated balance sheet date. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Gains or losses on translation are included in the foreign currency translation adjustment in shareholders’ equity in the consolidated balance sheets. Foreign operations that are integrated are translated using the temporal method. For foreign currency balances and integrated subsidiaries, monetary assets and liabilities are translated to Canadian dollars at the exchange rate in effect at the consolidated balance sheet date. Non-monetary assets and liabilities are translated at the exchange rate in effect when the assets were acquired or Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements 79 obligations incurred. Revenues and expenses are translated to Canadian dollars at the monthly average exchange rates. Provisions for depletion, depreciation and amortization are translated at the same rate as the related items. Gains or losses on translation are included in the consolidated statement of earnings. Gains or losses on the translation of long-term debt denominated in US dollars are either recognized in net earnings immediately, or in the foreign currency translation adjustment (note 8) for translation gains or losses for that portion of the US dollar denominated debt designated as a hedge of self-sustaining foreign operations. (J) REVENUE RECOGNITION Revenue from the production of crude oil and natural gas is recognized when title passes to the customer and delivery has taken place. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process. Revenue as reported represents the Company’s share and is presented before royalty payments to governments and other mineral interest owners. Revenue, net of royalties represents the Company’s share after royalty payments to governments and other mineral interest owners. (K) TRANSPORTATION COSTS Transportation costs incurred to transport crude oil and natural gas to customers are recorded as a separate cost in the consolidated statement of earnings. (L) PRODUCTION SHARING CONTRACT Production generated from Offshore West Africa is currently shared under the terms of various Production Sharing Contracts (“PSC”). Revenues are divided into cost recovery revenues and proﬁt revenues. Cost recovery revenues allow the Company to recover its share and the government’s share of capital and operating costs carried by the Company. Proﬁt revenues are allocated to the Company in accordance with its respective equity interest, after a portion has been allocated to the government. Cost recovery and proﬁt revenues are reported as sales revenues. The government’s share of revenues attributable to the Company’s equity interest, except for income tax, is reported as a royalty expense in accordance with the PSCs. (M) PETROLEUM REVENUE TAX The Company accounts for the United Kingdom petroleum revenue tax (“PRT”) by the life-of-the-ﬁeld method. The total future liability or recovery of PRT is estimated using current reserves and anticipated sales prices and costs. The estimated future PRT is apportioned to accounting periods on the basis of total estimated future operating income. Changes in the estimated total future PRT are accounted for prospectively. (N) INCOME TAX The Company follows the liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are recognized based on the estimated tax effects of temporary differences in the carrying value of assets and liabilities in the consolidated ﬁnancial statements and their respective tax bases, using income tax rates substantively enacted on the consolidated balance sheet date. The effect of a change in income tax rates on the future income tax assets and liabilities is recognized in net earnings in the period of the change. (O) STOCK-BASED COMPENSATION PLANS The Company accounts for its stock-based compensation plans using the intrinsic value method. The Company’s Stock Option Plan (the “Option Plan”) provides current employees with the right to elect to receive common shares or direct cash payment in exchange for options surrendered. A liability for potential cash settlements under the Option Plan is accrued over the vesting period of the stock options based on the difference between the exercise price of the stock options and the market price of the Company’s common shares. This liability is revalued at each reporting date to reﬂect changes in the market price of the Company’s common shares, with the net change recognized in net earnings, or capitalized during the construction period in the case of the Horizon Project. When stock options are surrendered for cash, the cash settlement paid reduces the outstanding liability. When stock options are exercised for common shares under the Option Plan, consideration paid by employees and any previously recognized liability associated with the stock options are recorded as share capital. The Company has an employee stock savings plan and a stock bonus plan. Contributions to the employee stock savings plan are recorded as compensation expense at the time of the contribution. Contributions to the stock bonus plan are recognized as compensation expense over the related vesting period. 80 Notes to the Consolidated Financial Statements (P) RISK MANAGEMENT ACTIVITIES The Company utilizes various derivative ﬁnancial instruments to manage its commodity price, currency and interest rate exposures. These derivative ﬁnancial instruments are not used for trading or speculative purposes. Changes in fair value of derivative ﬁnancial instruments designated as hedges are not recognized in net earnings until such time as the corresponding gains or losses on the related hedged items are also recognized. Changes in fair value of derivative ﬁnancial instruments not designated as hedges are recognized in the balance sheet each period with the offset reﬂected in risk management activities in the consolidated statements of earnings. The Company formally documents all 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 enters into commodity price contracts to manage anticipated sales of crude oil and natural gas production in order to protect cash ﬂow for capital expenditure programs. Gains or losses on these contracts are included in risk management activities. The Company enters into interest rate swap agreements 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. Gains or losses on interest rate swap contracts designated as hedges are included in interest expense. Gains or losses on non-designated interest rate contracts are included in risk management activities. Cross currency swap agreements 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. Gains or losses on cross currency swap contracts designated as hedges are included in interest expense. Gains or losses on the termination of ﬁnancial instruments that have been accounted for as hedges are deferred under other assets or liabilities on the consolidated balance sheets and amortized into net earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any unrealized derivative gain or loss is recognized immediately in net earnings. Gains or losses on the termination of ﬁnancial instruments that have not been accounted for as hedges are recognized in net earnings immediately. (Q) PER COMMON SHARE AMOUNTS The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. This method assumes that proceeds received from the exercise of in-the-money stock options not included as a liability are used to purchase common shares at the average market price during the year. The dilutive effect of convertible securities is calculated by applying the “if-converted” method, which assumes that the securities are converted at the beginning of the period and that income items are adjusted to net earnings. (R) RECENTLY ISSUED ACCOUNTING STANDARDS UNDER CANADIAN GAAP FINANCIAL INSTRUMENTS In January 2005, the CICA issued four new standards relating to the accounting for and disclosure of ﬁnancial instruments. • Section 3855 – “Financial Instruments – Recognition and Measurement” prescribes when a ﬁnancial asset, ﬁnancial liability, or non-ﬁnancial derivative is to be recognized on the balance sheet as well as its measurement amount. This Section also speciﬁes how ﬁnancial instruments gains and losses are to be presented. Transitional provisions for this Section vary based on the type of ﬁnancial instruments under consideration. • Section 3865 – “Hedges” expands on existing Accounting Guideline 13 – “Hedging Relationships,” and Section 1650 “Foreign Currency Translation,” by specifying how hedge accounting is to be applied and what disclosures are necessary when it is applied. Retroactive application of this Section is not permitted. • Section 1530 – “Comprehensive Income” introduces new standards for reporting and disclosure of comprehensive income. Comprehensive income is the change in equity (net assets) of the Company during a reporting period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Financial statements of prior periods are required to be restated only for non-ﬁnancial instrument items. • Section 3251 – “Equity” replaces Section 3250 “Surplus” and establishes standards for the presentation of equity and changes in equity during a reporting period. Financial statements of prior periods are required to be restated only for non-ﬁnancial instrument items. For all other items, comparative ﬁnancial statements presented are not restated, but an adjustment to the opening balance of accumulated other comprehensive income may be required. Notes to the Consolidated Financial Statements 81 The Company plans to adopt these new standards for interim and annual ﬁ nancial statements effective January 1, 2007. The effect on the Company’s consolidated ﬁ nancial statements cannot be reasonably determined at this time as the ﬁ nancial derivatives outstanding at December 31, 2006 and their related fair values are not known. (S) COMPARATIVE FIGURES Certain ﬁ gures provided for prior years have been reclassiﬁ ed to conform to the presentation adopted in 2005. Common share data has been restated to reﬂ ect the two-for-one share split in May 2005. 2. OTHER LONG-TERM ASSETS Deferred charges Risk management (note 10) Less: current portion 3. PROPERTY, PLANT AND EQUIPMENT 2005 Accumulated depletion and depreciation Cost Net Cost 2005 107 – 107 – 107 $ $ 2004 Accumulated depletion and depreciation Crude oil and natural gas North America North Sea Offshore West Africa Other Horizon Project Midstream Head office $ $ 22,258 2,703 1,547 27 2,169 251 124 29,079 $ $ 7,948 1,022 294 14 – 48 59 9,385 $ $ 14,310 1,681 1,253 13 2,169 203 65 19,694 $ $ 19,750 2,550 1,091 22 672 241 101 24,427 $ $ 6,356 727 190 14 – 32 44 7,363 2004 76 66 142 34 108 Net 13,394 1,823 901 8 672 209 57 17,064 $ $ $ $ During the year ended December 31, 2005, the Company capitalized administrative overhead of $41 million (2004 – $49 million, 2003 – $35 million) relating to exploration and development in the North Sea and Offshore West Africa and $236 million (2004 – $35 million, 2003 – $23 million) in North America, primarily related to the Horizon Project. During the year ended December 31, 2005, the Company capitalized $72 million (2004 and 2003 – $nil) in construction period interest costs related to the Horizon Project. Included in property, plant and equipment are unproved properties and major development projects that are not subject to depletion or depreciation: Crude oil and natural gas North America North Sea Offshore West Africa Other Horizon Project 2005 1,372 28 182 13 2,169 3,764 $ $ 2004 1,028 44 528 8 672 2,280 $ $ 82 Notes to the Consolidated Financial Statements The Company has used the following estimated benchmark future prices (“escalated pricing”) in its ceiling test prepared in accordance with Canadian GAAP, as at December 31, 2005: 2006 2007 2008 2009 2010 Average annual change thereafter Crude oil and NGLs North America WTI at Cushing (US$/bbl) Hardisty Heavy 12˚ API (C$/bbl) Edmonton Par (C$/bbl) North Sea and Offshore West Africa North Sea Brent (US$/bbl) Natural gas North America Henry Hub Louisiana (US$/mmbtu) AECO (C$/mmbtu) Huntingdon/Sumas (C$/mmbtu) 4. LONG-TERM DEBT $ $ $ $ $ $ $ 60.81 37.07 70.07 58.81 11.59 11.58 11.34 $ $ $ $ $ $ $ 61.61 37.29 70.99 59.58 10.11 10.84 10.70 $ $ $ $ $ $ $ 54.60 34.23 62.73 52.54 8.50 8.95 8.81 $ $ $ $ $ $ $ 50.19 32.27 57.53 48.10 7.58 7.87 7.73 Bank credit facilities Bankers’ acceptances US dollar bankers’ acceptances (2005 – US$nil, 2004 – US$471 million) Medium-term notes 7.40% unsecured debentures due March 1, 2007 4.95% unsecured debentures due June 1, 2015 Senior unsecured notes 7.69% due December 19, 2005 (2005 – US$nil, 2004 – US$125 million) Adjustable rate due May 27, 2009 (2005 – US$93 million, 2004 – US$93 million) Preferred securities 8.30% due June 25, 2011 (2005 – US$nil, 2004 – US$80 million) US dollar debt securities 6.70% due July 15, 2011 (2005 – US$400 million, 2004 – US$400 million) 5.45% due October 1, 2012 (2005 – US$350 million , 2004 – US$350 million) 4.90% due December 1, 2014 (2005 – US$350 million, 2004 – US$350 million) 7.20% due January 15, 2032 (2005 – US$400 million, 2004 – US$400 million) 6.45% due June 30, 2033 (2005 – US$350 million, 2004 – US$350 million) 5.85% due February 1, 2035 (2005 – US$350 million, 2004 – US$350 million) Less: current portion of long-term debt $ $ $ $ $ $ $ $ $ 47.76 31.15 54.65 45.64 7.32 7.57 7.43 1.5% 1.6% 1.5% 1.5% 1.5% 1.5% 1.5% 2005 2004 122 – 125 400 – 108 – 467 408 408 467 408 408 3,321 – 3,321 $ $ – 557 125 – 194 112 96 482 421 421 482 421 421 3,732 194 3,538 BANK CREDIT FACILITIES As at December 31, 2005 the Company had in place unsecured syndicated bank credit facilities of $3,425 million, comprised of: • a $100 million operating demand facility; • a two-tranche revolving credit and term loan facility of $1,825 million; and • a 5-year revolving and term loan facility of $1,500 million. The ﬁ rst $1,000 million tranche of the $1,825 million facility is fully revolving for a period of three years to June 2008. The second tranche of $825 million is fully revolving for a period of ﬁ ve years to June 2010. Both tranches are extendible annually for one-year periods at the mutual agreement of the Company and the lenders. If not extended, the full amount of the outstanding principal would be repayable at the end of year two following the initiation of the term period. The $1,500 million revolving credit and term loan facility has a ﬁ ve-year term, with three, one-year extension provisions. If the facility is not extended, the amount outstanding would be repayable in December 2009. These facilities provide that the borrowings may be made by way of operating advances, prime loans, bankers’ acceptances, US base rate loans or US dollar LIBOR advances, which bear interest at the bank’s prime rates or at money market rates plus applicable margins. The weighted average interest rate of the bank credit facilities outstanding at December 31, 2005, was 5.44% (2004 – 3.47%). The Company also has a £15 million demand overdraft credit facility related to the Company’s North Sea operations. At December 31, 2005 there were no amounts drawn on this facility. In addition to the outstanding debt, as at December 31, 2005 letters of credit aggregating $24 million (2004 – $24 million) have been issued. Notes to the Consolidated Financial Statements 83 MEDIUM-TERM NOTES In May 2005, the Company issued $400 million of debt securities maturing June 2015, bearing interest at 4.95%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. In May 2004, the Company repaid the $125 million 6.85% unsecured debentures due May 2004, which were issued under a previous medium-term note program. In January 2006, the Company issued $400 million of debt securities maturing January 2013, bearing interest at 4.50%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. After issuing these securities, the Company has $1.6 billion remaining on its $2 billion shelf prospectus ﬁ led in August 2005 that allows for the issue of medium-term notes in Canada until September 2007. If issued, these securities will bear interest as determined at the date of issuance. SENIOR UNSECURED NOTES In December 2005, the Company repaid the US$125 million 7.69% senior unsecured notes. The 6.42% senior unsecured notes were repaid in May 2004. The adjustable rate senior unsecured notes bear interest at 6.54% and have annual principal repayments of US$31 million commencing in May 2007, through May 2009. PREFERRED SECURITIES In September 2005, the Company redeemed the US$80 million 8.30% preferred securities due May 25, 2011 for cash consideration of US$91 million, including an early repayment premium of US$11 million as required under the Note Purchase Program. US DOLLAR DEBT SECURITIES In June 2005, the Company ﬁ led a short form prospectus that allows for the issue of up to US$2 billion of debt securities in the United States until July 2007. If issued, these securities will bear interest determined as at the date of issuance. In December 2004, the Company issued US$350 million of debt securities maturing December 2014, bearing interest at 4.90% and US$350 million of debt securities maturing February 2035, bearing interest at 5.85%. Proceeds from the securities issued were used to repay bankers’ acceptances under the Company’s bank credit facilities. The Company has entered into certain interest rate swap contracts to convert the ﬁ xed rate interest coupon into a ﬂ oating interest rate on the securities due December 2014 (note 10). REQUIRED DEBT REPAYMENTS Required debt repayments are as follows: Year 2006 2007 2008 2009 2010 Thereafter No debt repayments are reﬂ ected for the bank credit facilities due to the extendable nature of the facilities. 5. OTHER LONG-TERM LIABILITIES Asset retirement obligations Stock-based compensation Risk management (note 10) Other Less: current portion 84 Notes to the Consolidated Financial Statements 2005 1,112 891 885 17 2,905 1,471 1,434 $ $ Repayment $ $ $ $ $ $ $ $ – 161 36 36 – 2,966 2004 1,119 323 26 – 1,468 260 1,208 ASSET RETIREMENT OBLIGATIONS At December 31, 2005, the Company’s total estimated undiscounted costs to settle its asset retirement obligations with respect to crude oil and natural gas properties and facilities was approximately $3,325 million (2004 – $3,060 million). Payments to settle these asset retirement obligations will occur on an ongoing basis over a period of approximately 60 years and have been discounted using an average credit-adjusted risk-free interest rate of 6.8%. A reconciliation of the discounted asset retirement obligations is as follows: Asset retirement obligations Balance – beginning of year Liabilities incurred Liabilities settled Asset retirement obligation accretion Revision of estimates Foreign exchange Balance – end of year 2005 2004 1,119 47 (46) 69 (56) (21) 1,112 $ $ 897 339 (32) 51 (86) (50) 1,119 $ $ The Company’s pipelines have an indeterminant life and therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement obligations for these assets will be recorded in the ﬁ rst year in which the lives of the assets are determinable. STOCK-BASED COMPENSATION The Company recognizes a liability for the potential cash settlements under its Option Plan. The current portion represents the maximum amount of the liability payable within the next 12-month period if all vested options are surrendered for cash settlement. Stock-based compensation Balance – beginning of year Stock-based compensation provision Cash payment for options surrendered Transferred to common shares Capitalized to Horizon Project Balance – end of year Less: current portion of stock-based compensation 6. TAXES TAXES OTHER THAN INCOME TAX Current petroleum revenue tax Deferred petroleum revenue tax recovery Provincial capital taxes and surcharges INCOME TAX The provision for income tax is as follows: Current income tax expense Current income tax – North America Large Corporations Tax – North America Current income tax – North Sea Current income tax – Offshore West Africa Current income tax – other Future income tax expense Income tax 2005 2004 323 723 (227) (29) 101 891 629 262 2004 190 (45) 20 165 $ $ $ $ 171 249 (80) (38) 21 323 243 80 2003 106 (9) 10 107 $ $ $ $ 2005 181 (9) 22 194 2005 2004 2003 82 16 155 32 1 286 353 639 $ $ 89 11 2 13 1 116 474 590 $ $ 43 16 23 10 – 92 338 430 $ $ $ $ Notes to the Consolidated Financial Statements 85 285 (281) 16 (40) 20 (247) (31) (103) 4 10 430 2004 3,677 1,254 102 19 43 (418) (92) (54) (106) – (58) 4,367 (83) 4,450 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: Non-deductible portion of Canadian crown payments Canadian resource allowance Large Corporations Tax Deductible UK petroleum revenue tax Foreign tax rate differentials Federal income tax rate reductions Provincial income tax rate reductions Non-taxable portion of foreign exchange Attributed Canadian Royalty Income Other Income tax 2005 38.0% 716 2004 39.3% 849 $ 2003 41.1% 797 $ $ 309 (293) 16 (65) (1) – (19) (15) (21) 12 639 $ 221 (270) 11 (57) (31) – (66) (36) (4) (27) 590 $ $ The following table summarizes the temporary differences that give rise to the net future income tax asset and liability: Future income tax liabilities Property, plant and equipment Timing of partnership items Unrealized foreign exchange gain on long-term debt Risk management activities Other Future income tax assets Asset retirement obligations Capital loss carryforwards Attributed Canadian Royalty Income Stock-based compensation Risk management activities Deferred petroleum revenue tax Future income tax liability Less: future income tax asset Net future income tax liability 2005 3,960 1,646 112 – 31 (384) (79) (75) (300) (304) (59) 4,548 (487) 5,035 $ $ $ $ A signiﬁ cant portion of North America’s taxable income is generated by partnerships. Income taxes are incurred on the partnerships’ taxable income in the year following their inclusion in the Company’s consolidated net earnings. Current income tax will vary and is dependent upon the nature and amount of capital expenditures incurred in Canada. During 2005, the Government of British Columbia enacted legislation to reduce its corporate income tax rate by 1.5%, effective July 1, 2005, resulting in a $19 million reduction in the Company’s future income tax liability. During 2004, the Government of Alberta enacted legislation to reduce its corporate income tax rate by 1.0% effective April 1, 2004, resulting in a $66 million reduction in the Company’s future income tax liability. During 2003, the Government of Alberta enacted legislation to reduce its corporate income tax rate by 0.5% effective April 1, 2003. Also during 2003, the Canadian federal government enacted legislation to change the taxation of resource income. The legislation reduces the corporate income tax rate on resource income from 28% to 21% over ﬁ ve years beginning January 1, 2003. Over the same period, the deduction for resource allowance is being phased out and a deduction for actual crown royalties paid is being phased in. The Company’s future income tax liability was reduced by $31 million with respect to the Alberta corporate income tax rate reduction and by $247 million with respect to the federal resource income tax rate changes. 86 Notes to the Consolidated Financial Statements 7. SHARE CAPITAL AUTHORIZED 200,000 Class 1 preferred shares with a stated value of $10.00 each. Unlimited number of common shares without par value. ISSUED Common shares Numbers of shares (thousands) 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 536,361 837 – (850) 536,348 $ $ 2005 2004 Numbers of shares (thousands) 534,926 3,182 – (1,747) 536,361 $ $ Amount 2,353 24 38 (7) 2,408 Amount 2,408 9 29 (4) 2,442 SHARE SPLIT The Company’s shareholders approved a subdivision or share split of its issued and outstanding common shares on a two-for-one basis at the Company’s Annual and Special Meeting held on May 5, 2005. All common share and per common share amounts have been restated to retroactively reﬂ ect the share split. NORMAL COURSE ISSUER BID In January 2005, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock Exchange and the New York Stock Exchange to purchase up to 26,818,012 common shares or 5% of the outstanding common shares of the Company on the date of announcement, during the 12-month period beginning January 24, 2005 and ending January 23, 2006. As at December 31, 2005, the Company had purchased 850,000 common shares (2004 – 1,746,800 common shares) at an average price of $53.29 per common share (2004 – $19.00 per common share), for a total cost of $45 million (2004 – $33 million). Retained earnings was reduced by $41 million (2004 – $26 million), representing the excess of the purchase price of the common shares over their stated value. On January 20, 2006, the Company announced the renewal of its Normal Course Issuer Bid through the facilities of the Toronto Stock Exchange and the New York Stock Exchange to purchase up to 26,852,545 common shares or 5% of the outstanding common shares of the Company on the date of the announcement, during the 12-month period beginning January 24, 2006 and ending January 23, 2007. As at February 21, 2006, the Company had not purchased any additional shares under the Normal Course Issuer Bid. DIVIDEND POLICY The Company pays regular quarterly dividends in January, April, July and October of each year. On February 21, 2006, the Board of Directors set the Company’s regular quarterly dividend at $0.075 per common share (2005 – $0.059 per common share, 2004 – $0.050 per common share). STOCK OPTIONS The Option Plan provides for granting of stock options to employees. Stock options granted under the Option Plan have a maximum term of six years to expiry and vest equally over a ﬁ ve-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 permits the holder to purchase one common share of the Company at the stated exercise price. In June 2003 the Company approved a modiﬁ cation to its Option Plan providing the stock option holder the right to elect to receive a cash payment equal to the difference between the exercise price of the stock option and the market price of the Company’s common shares on the date of surrender, multiplied by the number of common shares covered by the stock options surrendered, in lieu of receiving common shares. The modiﬁ cation to the Option Plan was accounted for prospectively. Notes to the Consolidated Financial Statements 87 For the year ended December 31, 2005, the Company recorded stock-based compensation expense of $723 million (2004 – $249 million, 2003 – $200 million). In 2005, $101 million was capitalized to the Horizon Project (2004 – $21 million, 2003 – $10 million). As at December 31, 2005, the total liability for expected cash settlements under the Option Plan was $891 million (2004 – $323 million), of which $629 million (2004 – $243 million) was included as a current liability. During the year ended December 31, 2005, cash payments of $227 million were made for 7,523,000 stock options surrendered (2004 – cash payments of $80 million for 7,562,000 stock options surrendered). The following table summarizes information relating to stock options outstanding at December 31, 2005 and 2004: Outstanding – beginning of year Granted Exercised for common shares Surrendered for cash settlement Forfeited Outstanding – end of year Exercisable – end of year 2005 2004 Stock options (thousands) 32,522 7,959 (837) (7,523) (1,611) 30,510 8,677 $ $ $ $ $ $ $ Weighted average exercise price 12.37 32.51 9.81 10.49 19.36 17.79 11.21 Stock options (thousands) 35,578 9,722 (3,182) (7,562) (2,034) 32,522 7,632 $ $ $ $ $ $ $ Weighted average exercise price 9.86 17.95 7.55 9.36 13.86 12.37 9.92 The range of exercise prices of stock options outstanding and exercisable at December 31, 2005 was as follows: Range of exercise prices $7.85 – $9.99 $10.00 – $14.99 $15.00 – $19.99 $20.00 – $24.99 $25.00 – $29.99 $30.00 – $34.99 $40.00 – $44.99 $45.00 – $49.99 $50.00 – $54.99 $55.00 – $59.35 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 8,794 6,690 6,234 1,568 4,301 1,449 201 251 600 422 30,510 1.41 2.50 3.53 4.82 4.18 4.84 5.45 5.54 5.72 5.88 3.02 $ $ $ $ $ $ $ $ $ $ $ 9.63 11.74 17.07 22.89 26.26 33.22 40.25 47.16 54.43 55.89 17.79 4,835 2,780 883 176 3 – – – – – 8,677 $ $ $ $ $ $ $ $ $ $ $ 9.54 11.54 17.05 22.55 26.26 – – – – – 11.21 8. FOREIGN CURRENCY TRANSLATION ADJUSTMENT The foreign currency translation adjustment represents the unrealized gain (loss) on the Company’s net investment in self-sustaining foreign operations. Effective July 1, 2002, the Company designated certain US dollar denominated debt as a hedge against its net investment in US dollar-based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment. Balance – beginning of year Unrealized loss on translation of net investment Hedge of net investment with US dollar denominated debt, net of tax Balance – end of year 2005 2004 (6) (12) 9 (9) $ $ 3 (24) 15 (6) $ $ 88 Notes to the Consolidated Financial Statements 9. NET EARNINGS PER COMMON SHARE The following table provides a reconciliation between basic and diluted amounts per common share: (thousands of shares) Weighted average common shares outstanding – basic Effect of dilutive stock options (1) Assumed settlement of preferred securities with common shares Weighted average common shares outstanding – diluted Net earnings Interest on preferred securities, net of tax Revaluation of preferred securities, net of tax Diluted net earnings Net earnings per common share Basic Diluted 2005 2004(2) 2003(2) 536,650 – 1,775 538,425 1,050 4 (2) 1,052 1.96 1.95 536,223 – 4,461 540,684 1,405 5 (4) 1,406 2.62 2.60 $ $ $ $ 536,940 4,889 7,816 549,645 1,403 5 (18) 1,390 2.62 2.53 $ $ $ $ $ $ $ $ (1) The Option Plan described in note 7 results in a liability and expense for all outstanding stock options. As such, the potential common shares associated with the stock options are not included in diluted earnings per share effective from June 2003, the date of the modification. (2) Restated to reflect two-for-one share split in May 2005. 10. FINANCIAL INSTRUMENTS RISK MANAGEMENT On January 1, 2004, the fair values of all outstanding derivative ﬁ nancial instruments that were not designated as hedges for accounting purposes were recorded on the consolidated balance sheet, with an offsetting net deferred revenue amount. Subsequent net changes in the fair value of non-designated ﬁ nancial instruments have been recognized on the consolidated balance sheet and in net earnings. The estimated fair value for all derivative ﬁ nancial instruments is based on third party indications. As at December 31, 2005 and 2004, the estimated fair values of non-designated ﬁ nancial derivatives were comprised as follows: 2005 2004 Risk management mark-to-market Deferred revenue Risk management mark-to-market Deferred revenue Balance – beginning of year Net cost of put options outstanding as at December 31 Net change in fair value of financial instruments $ $ 66 190 $ (26) – $ 40 38 outstanding as at December 31 Amortization of deferred revenue Balance – end of year Less: put premium financing obligations Less: current portion (1) (943) – (687) (190) (877) 834 (43) $ $ – 18 (8) – (8) 8 – (1) The Company has negotiated payment of put option premiums with various counterparties at the time of actual settlement of the respective option. Net losses (gains) from risk management activities for the years ended December 31 were as follows: Net realized risk management loss Net unrealized risk management loss (gain) 2005 1,027 925 1,952 $ $ 26 – 104 (38) 66 34 32 2004 474 (40) 434 $ $ $ $ $ $ (40) – – 14 (26) – (26) 17 (9) 2003 148 – 148 As at December 31, 2005, the net unrecognized liability related to the estimated fair values of derivative ﬁ nancial instruments designated as hedges was $990 million (December 31, 2004 – net unrecognized asset of $33 million). Notes to the Consolidated Financial Statements 89 FINANCIAL CONTRACTS The Company’s ﬁ nancial instruments recognized in the consolidated balance sheets consist of cash, accounts receivable, accounts payable, accrued liabilities, risk management activities, stock-based compensation and long-term debt. The estimated fair values of ﬁ nancial instruments have been determined based on the Company’s assessment of available market information, appropriate valuation methodologies and third party indications. However, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The carrying value of cash, accounts receivable, accounts payable, accrued liabilities, stock-based compensation and long-term debt with variable interest rates approximate their fair value. The estimated fair values of other ﬁ nancial instruments were as follows: Asset (liability) Derivative financial instruments Fixed rate notes 2005 2004 Carrying value Fair value Carrying value Fair value $ $ (687) ( 3,199) $ $ (1,700) ( 3,367) $ $ 66 (3,175) $ $ 33 (3,364) COMMODITY PRICE RISK MANAGEMENT The Company uses certain derivative ﬁ nancial instruments to manage its commodity price exposures. These ﬁ nancial instruments are entered into solely for hedging purposes and are not used for trading or other speculative purposes. The following summarizes transactions outstanding as at December 31, 2005: Crude oil Crude oil price collars Crude oil puts (1) Brent differential swaps Remaining term Volume Average price Index Jan 2006 – Dec 2006 Jan 2006 – Dec 2006 Jan 2006 – Dec 2006 Mar 2006 – Jul 2006 Aug 2006 – Dec 2006 Jan 2007 – Dec 2007 Jan 2007 – Dec 2007 Jan 2006 – Dec 2006 Jan 2007 – Dec 2007 167,644 bbl/d 82,356 bbl/d 22,000 bbl/d 55,000 bbl/d 51,000 bbl/d 100,000 bbl/d 100,000 bbl/d 25,000 bbl/d 50,000 bbl/d US$38.26 – US$48.28 US$44.75 – US$76.93 C$46.53 – C$58.67 US$40.00 US$45.00 US$28.00 US$45.00 US$1.29 US$1.34 WTI WTI WTI WTI WTI WTI WTI WTI/Dated Brent WTI/Dated Brent (1) Subsequent to year end, the Company settled 17,000 bbl/d of the US$40.00 put options for 2006 and purchased 100,000 bbl/d of US$50.00 put options for 2007. Remaining term Volume Average price Natural gas AECO collars Jan 2006 – Mar 2006 Jan 2006 – Mar 2006 Jan 2006 – Mar 2006 Apr 2006 – Jun 2006 Apr 2006 – Jun 2006 Jul 2006 – Sep 2006 Jul 2006 – Sep 2006 Oct 2006 – Dec 2006 Oct 2006 – Dec 2006 Oct 2006 – Dec 2006 Jan 2007 – Mar 2007 700,000 GJ/d 400,000 GJ/d 100,000 GJ/d 993,000 GJ/d 100,000 GJ/d 725,000 GJ/d 100,000 GJ/d 244,000 GJ/d 100,000 GJ/d 464,000 GJ/d 700,000 GJ/d C$5.88 – C$8.78 C$6.00 – C$12.29 C$8.00 – C$27.75 C$5.71 – C$8.13 C$7.00 – C$14.16 C$5.60 – C$7.59 C$7.00 – C$14.16 C$5.60 – C$7.59 C$7.00 – C$14.16 C$7.50 – C$18.80 C$7.50 – C$18.80 Index AECO AECO AECO AECO AECO AECO AECO AECO AECO AECO AECO Commodity related derivative ﬁ nancial instruments designated as hedges at December 31, 2005, were all classiﬁ ed as cash ﬂ ow hedges. 90 Notes to the Consolidated Financial Statements INTEREST RATE RISK MANAGEMENT The Company is exposed to interest rate price risk on its ﬁxed rate long-term debt and to interest rate cash ﬂow-risk on its ﬂoating rate long-term debt. The Company enters into interest rate swap agreements to manage its ﬁxed to ﬂoating interest rate mix on long-term debt. The interest rate swap contracts require the periodic exchange of payments without the exchange of the notional principal amounts on which the payments are based. At December 31, 2005, the Company had the following interest rate swap contracts outstanding: Remaining term Amount ($ millions) Fixed rate Floating rate Interest rate Swaps – fixed to floating Swaps – floating to fixed Jan 2006 – Jan 2007 Jan 2006 – Oct 2012 Jan 2006 – Dec 2014 Jan 2006 – Mar 2007 US$200 (2) US$350 US$350 C$6 7.20% 5.45% 4.90% 7.36% LIBOR (1) + 2.23% LIBOR (1) + 0.81% LIBOR (1) + 0.38% CDOR (3) (1) London Interbank Offered Rate (2) Subsequent to year end the Company received approximately $1 million in settlement of the 7.20% fixed to floating rate swap. (3) Canadian Deposit Overnight Rate Interest rate related derivative ﬁnancial instruments designated as hedges at December 31, 2005, were all classiﬁed as fair value hedges. FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT The Company is exposed to foreign exchange rate risk in Canada on its US dollar denominated debt and on product sales based on US dollar denominated benchmarks. The Company is also exposed to foreign exchange rate risk on transactions conducted in foreign currencies in its foreign subsidiaries and in the carrying value of its self sustaining foreign subsidiaries. Cross currency swap agreements 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. The Company may also enter into foreign currency denominated ﬁnancial instruments to manage future US dollar denominated crude oil and natural gas sales. The Company has designated certain US dollar denominated debt as a hedge against its net investment in US dollar-based self-sustaining foreign operations (note 8). COUNTERPARTY CREDIT RISK MANAGEMENT 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 this risk by entering into sales contracts with only highly rated entities. In addition, the Company reviews 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. The Company is also 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 only highly rated ﬁnancial institutions and other entities. 11. COMMITMENTS The Company has committed to certain payments as follows: Product transportation and pipeline (1) Offshore equipment operating lease Offshore drilling Asset retirement obligations (2) Other (3) $ $ $ $ $ 2006 195 51 132 82 61 $ $ $ $ $ 2007 133 51 100 4 62 $ $ $ $ $ 2008 148 52 35 4 21 $ $ $ $ $ 2009 2010 Thereafter 94 51 – 4 29 $ $ $ $ $ 85 51 – 7 23 $ $ $ $ $ 1,111 180 – 3,224 8 (1) During the year, the Company entered into a 25 year pipeline transportation agreement commencing in 2008, related to future crude oil production. The agreement is renewable for successive 10-year periods at the Company’s option. During the initial term, annual toll payments before operating costs will be approximately $35 million. (2) Represents management’s estimate of the future undiscounted payments to settle asset retirement obligations related to resource properties, facilities, production platforms and pipelines, based on current legislation and industry operating practices. (3) Consists of future expenditures related primarily to office lease, electricity and crude oil processing. The Board of Directors has approved the construction costs for Phase 1 of the Horizon Project, which are budgeted to be $6.8 billion, including a contingency fund of $700 million, with $1.3 billion incurred in 2005, $2.6 billion to be incurred in 2006 and $2.9 billion to be incurred in 2007 and 2008. The Company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The Company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated ﬁnancial position. Notes to the Consolidated Financial Statements 91 12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Changes in non-cash working capital were as follows: Decrease (increase) in non-cash working capital Accounts receivable and other Accounts payable Accrued liabilities Net change in non-cash working capital Relating to: Operating activities Financing activities Investing activities Other cash flow information: Interest paid Taxes paid 2005 2004 2003 $ $ $ $ $ $ (498) 196 716 414 (147) 19 542 414 200 430 $ $ $ $ $ $ (329) 39 194 (96) (14) 6 (88) (96) 192 218 $ $ $ $ $ $ 35 125 122 282 (48) (11) 341 282 178 51 13. SEGMENTED INFORMATION The Company’s crude oil and natural gas activities are conducted in three geographic segments: North America, North Sea and Offshore West Africa. These activities relate to the exploration, development, production and marketing of crude oil, natural gas liquids and natural gas. The Company’s Horizon Project has been classiﬁ ed as a separate segment. As the bitumen will be recovered through mining operations, this project constitutes a distinct segment from crude oil and natural gas activities. There are currently no revenues for this project and all directly related expenditures have been capitalized. Midstream activities include the Company’s pipeline operations and an electricity co-generation system. Activities that are not included in the above segments are included in the segmented information as other. Inter-segment eliminations include internal transportation and electricity charges. North America 2005 2004 2003 Crude oil and natural gas North Sea 2004 2003 2005 $ 7,932 (1,350) 6,582 $ 5,979 (1,003) 4,976 $ 5,021 (868) 4,153 $ 1,659 (3) 1,656 $ 1,317 (2) 1,315 $ 953 1 954 1,211 287 976 256 845 264 1,595 1,444 1,209 34 28 26 870 3,997 362 3,066 157 2,501 379 20 306 34 157 896 370 32 265 22 112 801 314 30 252 36 (9) 623 Offshore West Africa 2005 2004 2003 $ 485 (13) 472 $ 222 (6) 216 $ 155 (5) 150 53 – 104 1 – 158 36 – 53 1 – 90 38 – 41 – – 79 $ 2,585 $ 1,910 $ 1,652 $ 760 $ 514 $ 331 $ 314 $ 126 $ 71 Segmented revenue Less: royalties Revenue, net of royalties Segmented expenses Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Realized risk management activities Total segmented expenses Segmented earnings before the following Non-segmented expenses Administration Stock-based compensation Interest Unrealized risk management activities Foreign exchange gain Total non-segmented expenses Earnings before taxes Taxes other than income tax Current income tax expense Future income tax expense Net earnings 92 Notes to the Consolidated Financial Statements 2005 Midstream 2004 Inter-segment elimination and other 2003 2005 2004 2003 $ 77 – 77 24 – 8 – – 32 $ 68 – 68 20 – 7 – – 27 $ 61 – 61 15 – 7 – – 22 $ (46) – (46) (4) (37) – – – (41) $ (39) – (39) (2) (38) – – – (40) $ (35) – (35) (3) (32) – – 2005 $ 10,107 (1,366) 8,741 Total 2004 $ 7,547 (1,011) 6,536 2003 $ 6,155 (872) 5,283 1,663 270 1,400 250 1,209 262 2,013 1,769 1,509 69 51 62 – (35) 1,027 5,042 474 3,944 148 3,190 $ 45 $ 41 $ 39 $ (5) $ 1 $ – 3,699 2,592 2,093 151 723 149 925 (132) 1,816 1,883 194 286 353 $ 1,050 125 249 189 (40) (91) 432 2,160 165 116 474 $ 1,405 87 200 201 – (335) 153 1,940 107 92 338 $ 1,403 Notes to the Consolidated Financial Statements 93 CAPITAL EXPENDITURES 2005 Non-cash and fair value adjustments (1) 2004 Non-cash and fair value adjustments (1) Cash expenditures Capitalized costs Cash expenditures Capitalized costs Crude oil and natural gas North America North Sea Offshore West Africa Other Horizon Project Midstream Head office $ $ 2,530 387 439 5 3,361 1,499 4 22 4,886 $ $ (22) (136) 27 – (131) – – – (131) $ $ 2,508 251 466 5 3,230 1,499 4 22 4,755 $ $ 3,329 608 295 1 4,233 291 16 35 4,575 (1) Asset retirement obligations, future income tax adjustments on non-tax base assets, and other fair value adjustments. Segmented property, plant and equipment, net Crude oil and natural gas North America North Sea Offshore West Africa Other Horizon Project Midstream Head office Segmented assets Crude oil and natural gas North America North Sea Offshore West Africa Other Horizon Project Midstream Head office $ $ $ $ $ $ 508 172 – – 680 – – – 680 2005 14,310 1,681 1,253 13 2,169 203 65 19,694 2005 15,939 1,950 1,371 30 2,239 258 65 21,852 $ $ $ $ $ $ 3,837 780 295 1 4,913 291 16 35 5,255 2004 13,394 1,823 901 8 672 209 57 17,064 2004 14,390 2,036 914 35 672 268 57 18,372 14. BUSINESS COMBINATIONS PETROVERA PARTNERSHIP In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as the Petrovera Partnership (“Petrovera”), for $471 million. The acquisition was accounted for based on the purchase method. Results from Petrovera are consolidated with the results of the Company effective from the date of acquisition. The allocation of the purchase price to assets acquired and liabilities assumed based on their fair values was as follows: Purchase price: Cash consideration Cash acquired Non-cash working capital deficit assumed Total purchase price Purchase price allocated as follows: Property, plant and equipment Future income tax liability Asset retirement obligation 94 Notes to the Consolidated Financial Statements February 1, 2004 $ $ $ $ 467 (23) 27 471 643 (129) (43) 471 15. DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Company’s consolidated ﬁ nancial statements have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”). These principles conform in all material respects with those in the United States (“US GAAP”) except for those noted below. Differences arising from US GAAP disclosure requirements are not addressed. The application of US GAAP would have the following effects on consolidated net earnings as reported: (millions of Canadian dollars, except per common share amounts) Notes 2005 2004 Net earnings – Canadian GAAP Adjustments Depletion, net of tax of $3 million (2004 – $2 million; 2003 – $3 million) Derivative financial instruments and hedging activities, net of tax of $11 million (2004 – $7 million; 2003 – $20 million) Capitalized interest, net of tax of $11 million Cumulative effect of change in accounting policy, net of tax of $3 million Net earnings – US GAAP Net earnings – US GAAP per common share Basic Diluted Comprehensive income under US GAAP would be as follows: (millions of Canadian dollars) Net earnings – US GAAP Derivative financial instruments and hedging activities, net of tax of $312 million (2004 – $3 million; 2003 – $9 million) Foreign currency translation adjustment Comprehensive income (A) (B) (C) (D) $ 1,050 $ 1,405 $ 4 4 (19) – – 1,035 1.93 1.93 $ $ $ (9) 16 – 1,416 2.64 2.62 $ $ $ $ $ $ Notes 2005 2004 $ 1,035 $ 1,416 $ (B) (E) $ (635) (3) 397 $ 8 (9) 1,415 The application of US GAAP would have the following effects on the consolidated balance sheets as reported: (millions of Canadian dollars) Current assets Property, plant and equipment Other long-term assets Current liabilities Long-term debt Other long-term liabilities Future income tax Shareholders’ equity (millions of Canadian dollars) Current assets Property, plant and equipment Other long-term assets Current liabilities Long-term debt Other long-term liabilities Future income tax Shareholders’ equity Notes (B) (A,C) (B) (B) (B) (A,B,C) (B,E) Notes (B) (A,C) (B) (A,B,C) (B,E) Canadian GAAP 2005 Increase (decrease) $ $ $ $ $ $ $ $ 2,051 19,694 107 21,852 3,825 3,321 1,434 5,035 8,237 21,852 Canadian GAAP 1,200 17,064 108 18,372 1,852 3,538 1,208 4,450 7,324 18,372 $ $ $ $ $ $ $ $ 338 (20) – 318 1,005 (18) 8 (5) (672) 318 2004 Increase (decrease) (33) (27) – (60) (44) – – 6 (22) (60) 2003 1,403 4 (49) – (4) 1,354 2.52 2.44 2003 1,354 20 (23) 1,351 US GAAP 2,389 19,674 107 22,170 4,830 3,303 1,442 5,030 7,565 22,170 US GAAP 1,167 17,037 108 18,312 1,808 3,538 1,208 4,456 7,302 18,312 $ $ $ $ $ $ $ $ $ Notes to the Consolidated Financial Statements 95 NOTES: (A) Under Canadian full cost accounting rules, costs capitalized in each cost centre, net of future income taxes, are limited to an amount equal to the undiscounted, future net revenues from proved reserves using estimated future prices and costs, plus the carrying amount of unproved properties and major development projects (the “ceiling test”). Under the full cost method of accounting as set forth by the US Securities and Exchange Commission, the ceiling test differs from Canadian GAAP in that future net revenues from proved reserves are based on prices and costs as at the balance sheet date (“constant dollar pricing”) and are discounted at 10%. (B) The Company accounts for its derivative ﬁnancial instruments under Canadian GAAP as described in note 1(P). For US GAAP purposes, Financial Accounting Standards Board Statement (“FAS”) 133, “Accounting for Derivative Financial Instruments and Hedging Activities,” as amended by FAS 138 and FAS 149, establishes US GAAP accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in the consolidated statements of earnings each period. If the derivative is designated as a cash ﬂow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income (“OCI”) each period and are recognized in the consolidated statements of earnings when the hedged item is recognized. Therefore, ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash ﬂow hedges. The determination of hedge effectiveness and the measurement of hedge ineffectiveness of cash ﬂow hedges is based on a combination of third party indications and internally derived valuations. The Company uses these valuations to estimate the fair values of the underlying physical commodity contracts. (C) Under Canadian GAAP, the Company began capitalizing interest on the Horizon Project when the Board of Directors approval was received in 2005. For US GAAP, capitalization of interest on projects constructed over time is mandatory and interest has been capitalized to the costs of construction beginning in 2004. (D) Under Canadian GAAP, when the asset retirement obligation standard was adopted prior period comparative balances were restated to reﬂect the effect of the new standard on that year. Under US GAAP, when the asset retirement obligation standard was adopted the cumulative effect of the new standard on prior periods was included in earnings in the year adopted. (E) Under US GAAP, exchange gains and losses arising from the translation of self-sustaining foreign operations are included in comprehensive income. (F) Recently issued accounting standards under US GAAP: SHARE-BASED PAYMENT In December 2004, the Financial Accounting Standards Board (“FASB”) issued FAS 123(R) “Share-Based Payment,” which is a revision of FAS 123. This standard requires all companies to reﬂect stock based compensation in their statement of earnings for US GAAP. The fair value of stock options must be recognized at the date of grant using option pricing models. The fair value must be remeasured each quarter and changes in fair value must ﬂow through the statement of earnings. This is a difference from Canadian GAAP, where the Company’s options are valued at the difference between the exercise price and the stock price. This standard is effective for the ﬁrst interim or annual reporting period of a registrant’s ﬁrst ﬁscal year beginning on or after June 15, 2005. The Company plans to adopt this standard January 1, 2006. ACCOUNTING CHANGES AND ERROR CORRECTIONS In May 2005, the FASB issued FAS 154 “Accounting Changes and Error Corrections,” which replaces FAS 3 “Reporting Accounting Changes in Interim Financial Statements” and APB Opinion 20 “Accounting Changes.” The previous standards required that changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. The new standard requires that accounting changes be applied retrospectively and that prior accounting periods be restated as if the accounting principle had always been used. This change eliminates a difference from Canadian GAAP. The new standard will be applied to all future US GAAP accounting policy changes. 96 Notes to the Consolidated Financial Statements Supplementary Oil & Gas Information (unaudited) This supplementary oil and natural gas information is provided in accordance with the United States FAS 69, “Disclosures about Oil and Gas Producing Activities”, and where applicable is reconciled to the US GAAP ﬁnancial information. NET PROVED OIL AND NATURAL GAS RESERVES The Company retains qualiﬁed independent reserves evaluators to evaluate the Company’s proved oil and natural gas reserves. • For the year ended December 31, 2005, the reports by Sproule Associates Limited (“Sproule”) and Ryder Scott Company covered 100% of the Company’s conventional reserves; • For the year ended December 31, 2004, the reports by Sproule and Ryder Scott Company covered 100% of the Company’s conventional reserves; • For the year ended December 31, 2003, the reports by Sproule covered 100% of the Company’s conventional reserves; and • For the year ended December 31, 2002, the reports by Sproule covered 89% of the Company’s conventional reserves. Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. Estimates of oil and natural gas reserves are subject to uncertainty and will change as additional information regarding producing ﬁelds and technology becomes available and as future economic and operating conditions change. The following table summarizes the Company’s proved and proved developed conventional crude oil and natural gas reserves, net of royalties, as at December 31, 2005, 2004 and 2003: Crude oil and NGLs (mmbbl) Net proved reserves Reserves, December 31, 2002 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revisions of previous estimates Reserves, December 31, 2003 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revisions of previous estimates Reserves, December 31, 2004 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revisions of previous estimates Reserves, December 31, 2005 Net proved developed reserves: December 31, 2002 December 31, 2003 December 31, 2004 December 31, 2005 North America North Sea Offshore West Africa 571 1 63 7 – (56) 2 588 17 25 36 – (66) 48 648 98 3 – (3) (70) 18 694 340 348 367 402 202 – – 27 – (21) 14 222 – 45 38 – (24) 22 303 – 3 – – (25) 9 290 107 138 218 214 75 13 – – – (4) 1 85 – – – – (4) 34 115 – 2 15 – (8) 10 134 27 23 20 80 Total 848 14 63 34 – (81) 17 895 17 70 74 – (94) 104 1,066 98 8 15 (3) (103) 37 1,118 474 509 605 696 Supplementary Oil & Gas Information 97 Natural gas (bcf) Net proved reserves Reserves, December 31, 2002 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revisions of previous estimates Reserves, December 31, 2003 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revision of previous estimates Reserves, December 31, 2004 Extensions and discoveries Improved recovery Purchases of reserves in place Sales of reserves in place Production Revision of previous estimates Reserves, December 31, 2005 Net proved developed reserves: December 31, 2002 December 31, 2003 December 31, 2004 December 31, 2005 North America North Sea Offshore West Africa 2,446 58 251 50 (3) (355) (21) 2,426 334 80 182 (8) (383) (40) 2,591 506 30 6 (23) (411) 42 2,741 2,185 2,140 2,213 2,300 71 – – 19 – (17) (11) 62 – – 10 – (18) (27) 27 – – – – (7) 9 29 57 46 12 16 71 6 – – – (3) (10) 64 – – – – (3) 11 72 – – – – (1) 1 72 27 12 5 10 CAPITALIZED COSTS RELATED TO OIL AND NATURAL GAS ACTIVITIES North America 20,886 1,372 22,258 (7,993) 14,265 North America 18,749 1,028 19,777 (6,410) 13,367 North America 15,125 789 15,914 (4,984) 10,930 $ $ $ $ $ $ $ $ $ $ $ $ North Sea 2,675 28 2,703 (1,022) 1,681 North Sea 2,506 44 2,550 (727) 1,823 North Sea 1,905 56 1,961 (522) 1,439 2005 Offshore West Africa $ $ 1,365 182 1,547 (294) 1,253 2004 Offshore West Africa $ $ 563 528 1,091 (190) 901 2003 Offshore West Africa $ $ 566 231 797 (140) 657 $ $ $ $ $ $ Other 14 13 27 (14) 13 Other 14 8 22 (14) 8 Other 14 6 20 (12) 8 $ $ $ $ $ $ (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 98 Supplementary Oil & Gas Information Total 2,588 64 251 69 (3) (375) (42) 2,552 334 80 192 (8) (404) (56) 2,690 506 30 6 (23) (419) 52 2,842 2,269 2,198 2,230 2,326 Total 24,940 1,595 26,535 (9,323) 17,212 Total 21,832 1,608 23,440 (7,341) 16,099 Total 17,610 1,082 18,692 (5,658) 13,034 COSTS INCURRED IN OIL AND NATURAL GAS ACTIVITIES (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Finding and development costs Asset retirement costs Actual retirement expenditures Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Finding and development costs Asset retirement costs Actual retirement expenditures Costs incurred (millions of Canadian dollars) Property acquisitions Proved Unproved Exploration Development Finding and development costs Asset retirement costs Actual retirement expenditures Costs incurred North America North Sea 2005 Offshore West Africa $ $ $ $ $ $ (448) 210 360 2,288 2,410 98 (46) 2,462 North America 1,748 298 290 1,403 3,739 98 (32) 3,805 North America 236 116 190 1,227 1,769 80 (30) 1,819 $ $ $ $ $ $ (3) – 22 368 387 (136) – 251 $ $ 63 (52) 16 412 439 27 – 466 North Sea 2004 Offshore West Africa 302 4 11 308 625 165 – 790 $ $ – – 35 259 294 (10) – 284 North Sea 2003 Offshore West Africa 100 23 41 193 357 59 (1) 415 $ $ – – 27 148 175 9 (9) 175 $ $ $ $ $ $ Other Total – – 5 – 5 – – 5 $ $ (388) 158 403 3,068 3,241 (11) (46) 3,184 Other Total – – 2 – 2 – – 2 $ $ 2,050 302 338 1,970 4,660 253 (32) 4,881 Other Total – – 7 – 7 – – 7 $ $ 336 139 265 1,568 2,308 148 (40) 2,416 Supplementary Oil & Gas Information 99 RESULTS OF OPERATIONS FROM OIL AND NATURAL GAS PRODUCING ACTIVITIES The Company’s results of operations from oil and natural gas producing activities for the years ended December 31, 2005, 2004 and 2003 are summarized in the following tables: (millions of Canadian dollars) Oil and natural gas revenue, net of royalties Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Oil and natural gas revenue, net of royalties Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations (millions of Canadian dollars) Oil and natural gas revenue, net of royalties Production Transportation Depletion, depreciation and amortization Asset retirement obligation accretion Petroleum revenue tax Income tax Results of operations North America 5,727 (1,211) (287) (1,588) (34) – (1,007) 1,600 North America 4,579 (976) (256) (1,438) (28) – (690) 1,191 North America 3,961 (845) (263) (1,203) (23) – (673) 954 $ $ $ $ $ $ $ $ $ $ $ $ North Sea 1,499 (379) (20) (306) (34) (172) (235) 353 North Sea 1,203 (370) (32) (265) (22) (145) (148) 221 2005 Offshore West Africa 472 (53) – (104) (1) – (110) 204 $ $ 2004 Offshore West Africa 216 (36) – (53) (1) – (44) 82 $ $ 2003 North Sea Offshore West Africa 962 (314) (30) (250) (39) (97) (93) 139 $ $ 150 (38) (1) (42) (1) – (24) 44 $ $ $ $ $ $ Total 7,698 (1,643) (307) (1,998) (69) (172) (1,352) 2,157 Total 5,998 (1,382) (288) (1,756) (51) (145) (882) 1,494 Total 5,073 (1,197) (294) (1,495) (63) (97) (790) 1,137 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED OIL AND NATURAL GAS RESERVES AND CHANGES THEREIN The following standardized measure of discounted future net cash ﬂ ows from proved oil and natural gas reserves has been computed using year-end sales prices and costs and year-end statutory income tax rates. A discount factor of 10% has been applied in determining the standardized measure of discounted future net cash ﬂ ows. The Company does not believe that the standardized measure of discounted future net cash ﬂ ows will be representative of actual future net cash ﬂ ows and should not be considered to represent the fair value of the oil and natural gas properties. Actual net cash ﬂ ows will differ from the presented estimated future net cash ﬂ ows due to several factors including: • Future production will include production not only from proved properties, but may also include production from probable and potential reserves; • Future production of oil and natural gas from proved properties will differ from reserves estimated; • Future production rates will vary from those estimated; • Future rather than year-end sales prices and costs will apply; • Economic factors such as interest rates, income tax rates, regulatory and ﬁ scal environments and operating conditions will change; • Future estimated income taxes do not take into account the effects of future exploration expenditures; and • Future development and site restoration costs will differ from those estimated. 100 Supplementary Oil & Gas Information Future net revenues, development, production and restoration costs have been based upon the estimates referred to above. The following tables summarize the Company’s future net cash ﬂ ows relating to proved oil and natural gas reserves based on the standardized measure as prescribed in FAS 69: (millions of Canadian dollars) Future cash inflows Future production costs Future development and site restoration costs 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 and site restoration costs 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 and site restoration costs Future income taxes Future net cash flows 10% annual discount for timing of future cash flows Standardized measure of future net cash flows North America 52,266 (17,310) (3,916) (10,272) 20,768 (7,793) 12,975 North America 31,727 (10,995) (2,944) (6,438) 11,350 (4,385) 6,965 North America 32,720 (9,480) (2,393) (7,295) 13,552 (6,203) 7,349 $ $ $ $ $ $ $ $ $ $ $ $ North Sea 19,961 (6,130) (3,099) (6,631) 4,101 (1,144) 2,957 North Sea 15,526 (6,302) (2,832) (3,783) 2,609 (691) 1,918 North Sea 9,099 (3,015) (1,749) (2,801) 1,534 (336) 1,198 2005 Offshore West Africa 8,515 (1,803) (1,032) (2,092) 3,588 (1,068) 2,520 $ $ 2004 Offshore West Africa 5,249 (1,137) (631) (1,242) 2,239 (634) 1,605 $ $ 2003 Offshore West Africa $ $ 3,192 (1,179) (697) – 1,316 (432) 884 Total 80,742 (25,243) (8,047) (18,995) 28,457 (10,005) 18,452 Total 52,502 (18,434) (6,407) (11,463) 16,198 (5,710) 10,488 Total 45,011 (13,674) (4,839) (10,096) 16,402 (6,971) 9,431 $ $ $ $ $ $ The principal sources of change in the standardized measure of discounted future net cash ﬂ ows are summarized in the following table: (millions of Canadian dollars) Sales of 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 2005 (5,785) 11,056 3,596 (971) 469 (130) 961 1,812 1,414 (4,458) 7,964 10,488 18,452 $ $ 2004 (4,331) (553) 2,120 (894) 1,386 (20) 1,431 1,558 1,357 (997) 1,057 9,431 10,488 $ $ 2003 (3,582) (2,750) 1,360 (346) 594 (8) 144 2,000 (1,411) 426 (3,573) 13,004 9,431 $ $ Supplementary Oil & Gas Information 101 Ten-Year Review Years ended December 31 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 FINANCIAL INFORMATION (C$ millions, except per share amounts) Net earnings Per share – basic (1) Cash flow from operations (2) Per share – basic (1) Capital expenditures, net of dispositions (including business combinations) Balance Sheet information Working capital (deficiency) surplus Property, plant and equipment, net Total assets Long-term debt Shareholders’ equity SHARE INFORMATION Common shares outstanding (thousands) Weighted average shares outstanding (thousands) Dividends declared per common share 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 cash flow (3) Debt to book capitalization (3) Return on average common shareholders’ equity, after tax (3) Debt to EBITDA (3) Daily production before royalties per 1,403 1,405 1,050 88 $ 1.96 $ 2.62 $ 2.62 $ 1.06 $ 1.32 $ 1.62 $ 0.51 $ 0.08 $ 0.26 $ 0.27 360 $ 9.36 $ 7.03 $ 5.88 $ 4.41 $ 3.96 $ 4.04 $ 1.74 $ 1.12 $ 1.28 $ 1.08 1,884 3,769 1,920 2,254 3,160 5,021 213 724 639 503 539 444 758 104 31 4,932 4,633 2,506 4,069 1,885 2,823 1,901 610 1,119 1,204 (652) (505) (14) (1,774) 19,694 21,852 3,321 8,237 17,064 18,372 3,538 7,324 13,714 14,643 2,748 6,006 12,934 13,793 4,200 4,754 58 36 (6) (77) (1) 4,679 3,135 2,831 1,993 8,766 7,439 4,976 3,329 3,016 2,144 9,290 8,051 2,788 2,573 2,157 1,426 1,136 588 3,928 3,297 1,962 1,317 1,250 1,108 (19) 536,348 536,361 534,926 535,104 484,804 489,116 445,816 399,236 395,276 389,532 536,650 536,223 536,940 511,532 485,200 466,804 415,624 397,324 392,168 332,984 – $ 0.24 $ 0.20 $ 0.15 $ 0.13 $ 0.10 $ – $ – $ – $ – $ 637,992 606,024 590,702 619,316 534,976 567,412 430,460 410,440 402,152 396,888 $ 62.00 $ 27.58 $ 16.81 $ 13.64 $ 13.09 $ 14.05 $ 9.65 $ 7.88 $ 11.06 $ 9.85 $ 24.28 $ 15.96 $ 11.30 $ 9.40 $ 8.98 $ 7.45 $ 4.95 $ 4.56 $ 7.23 $ 4.81 $ 57.63 $ 25.63 $ 16.34 $ 11.70 $ 9.58 $ 10.38 $ 8.81 $ 5.75 $ 7.65 $ 9.40 251,554 125,468 46,916 31,864 20,764 3,172 – – – $ 54.05 $ 22.37 $ 12.85 $ 8.72 $ 8.63 $ 9.46 $ $ 19.74 $ 11.94 $ 7.32 $ 5.89 $ 5.70 $ 6.19 $ $ 49.62 $ 21.39 $ 12.61 $ 7.42 $ 6.10 $ 6.88 $ – $ – $ – $ – $ – $ – $ – $ – $ – $ – – – – 0.7x 28.7% 1.0x 33.8% 0.9x 32.8% 1.9x 47.1% 1.5x 41.7% 1.4x 44.0% 3.0x 52.4% 3.2x 52.0% 2.3x 47.6% 1.6x 34.7% 14.3% 0.6x 21.4% 0.9x 25.6% 0.8x 13.0% 1.7x 17.7% 1.4x 28.8% 1.2x 13.0% 2.6x 2.4% 2.9x 8.8% 4.8x 10.9% 3.0x ten thousand common shares (boe/d) 10.3 9.6 8.5 8.2 7.4 6.6 5.0 4.7 4.5 3.6 Conventional proved and probable reserves per common share (boe) (4) 4.8 4.3 4.0 3.3 3.1 2.9 2.4 1.9 1.7 1.3 Net asset value per common share (1)(5) $ 60.44 $ 33.13 $ 23.35 $ 19.57 $ 16.88 $ 20.54 $ 12.33 $ 8.08 $ 6.80 $ 6.46 (1) Restated to reflect two-for-one share splits in May 2004 and May 2005. (2) Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. The Company evaluates its performance based on earnings and cash flow. Cash flow from operations may not be comparable to similar measures used by other companies. (3) Refer to the MD&A, page 62, “Liquidity and Capital Resources”, for the definitions of these items. (4) Based upon constant dollar Company gross reserves (before royalties), using year-end common shares outstanding. (5) Based upon 10% discounted, forcast price pre-tax proved and probable net present values as reported in the Company’s AIF for conventional reserves, with $250/acre added for core undeveloped land in 2005 and $75/acre for all years prior, less long-term debt and existing asset liabilities and adjusted for working capital. See reserves disclosures on pages 40 to 44. 102 Ten-Year Review Years ended December 31 2005 2004 2003 2002 2001 2000 1999 1998 1997 1996 OPERATING INFORMATION Conventional crude oil and NGLs (mmbbl) Company gross proved reserves (before royalties) North America North Sea Offshore West Africa Company gross proved and probable reserves (before royalties) North America North Sea Offshore West Africa Conventional natural gas (bcf) Company gross proved reserves (before royalties) North America North Sea Offshore West Africa Company gross proved and probable reserves (before royalties) North America North Sea Offshore West Africa Total proved reserves 785 290 148 1,223 695 303 125 672 222 106 1,123 1,000 665 203 94 962 1,154 417 230 1,801 992 415 214 1,621 977 317 187 1,481 742 277 162 1,181 644 83 61 788 740 106 111 957 643 102 36 781 731 134 46 911 554 – – 554 640 – – 640 284 – – 284 380 – – 380 257 – – 257 329 – – 329 136 – – 136 185 – – 185 3,378 29 83 3,490 3,202 27 81 3,310 3,006 62 86 3,154 3,048 71 90 3,209 2,566 94 69 2,729 2,360 91 65 2,516 2,183 – – 2,183 1,901 – – 1,901 1,716 – – 1,716 1,566 – – 1,566 4,372 69 127 4,100 57 102 4,568 4,259 3,611 101 111 3,823 3,450 89 120 3,659 2,915 118 96 3,129 2,762 114 84 2,960 2,547 – – 2,547 2,211 – – 2,211 2,078 – – 2,078 1,926 – – 1,926 (before royalties) (mmboe) 1,804 1,674 1,526 1,497 1,243 1,200 918 601 543 397 Total proved and probable reserves (before royalties) (mmboe) 2,562 2,330 2,118 1,791 1,479 1,404 1,065 749 675 506 Oil sands, mining (mmbbl) Gross proved and probable reserves (before royalties) Bitumen Synthetic crude oil * Daily production (before royalties) Crude oil and NGLs (mbbl/d) North America North Sea Offshore West Africa Natural gas (mmcf/d) North America North Sea Offshore West Africa Total production 3,430 2,878 – – – – – – – – – – – – – – – – – – 222 68 23 313 206 65 12 283 175 57 10 242 169 39 7 215 1,416 19 4 1,330 50 8 1,439 1,388 1,245 46 8 1,299 1,204 27 1 1,232 167 36 3 206 906 12 – 918 155 17 2 174 793 1 – 794 87 – – 87 721 – – 721 76 – – 76 673 – – 673 71 – – 71 626 – – 626 37 – – 37 499 – – 499 (before royalties) (mboe/d) 553 514 459 421 359 306 207 188 175 120 Product pricing Average crude oil and NGLs price ($/bbl) Average natural gas price ($/mcf) 46.86 8.57 37.99 6.50 32.66 6.21 31.22 3.77 23.45 5.45 31.89 4.92 22.26 2.52 11.98 2.11 18.99 1.97 24.73 1.67 * SCO reserves are based upon upgrading of the bitumen reserves. The reserves shown for bitumen and SCO are not additive. Ten-Year Review 103 Corporate information BOARD OF DIRECTORS Catherine M. Best (1) (2 – Chair) (3) Executive Vice-President, Risk Management & Chief Financial Ofﬁcer, Calgary Health Region Calgary, Alberta N. Murray Edwards (5) President, Edco Financial Holdings Ltd. Calgary, Alberta Honourable Gary A. Filmon, P.C., O.M. (1) (2) (4) Consultant, Exchange Group Winnipeg, Manitoba Ambassador Gordon D. Gifﬁn (1) (2) (4 – Chair) Senior Partner, McKenna Long & Aldridge LLP Atlanta, Georgia John G. Langille Vice-Chairman, Canadian Natural Resources Limited Calgary, Alberta Keith A. J. MacPhail (5) (6) Chairman, President & Chief Executive Ofﬁcer, Bonavista Energy Trust Calgary, Alberta MANAGEMENT COMMITTEE Allan P. Markin Chairman of the Board N. Murray Edwards Vice-Chairman of the Board John G. Langille Vice-Chairman of the Board Steve W. Laut President & Chief Operating Ofﬁcer Réal M. Cusson Senior Vice-President, Marketing Réal J.H. Doucet Senior Vice-President, Oil Sands Allen M. Knight Senior Vice-President, International & Corporate Development Tim S. McKay Senior Vice-President, North American Operations Douglas A. Proll Chief Financial Ofﬁcer & Senior Vice-President, Finance Allan P. Markin (6) Chairman of the Board, Canadian Natural Resources Limited Calgary, Alberta Norman F. McIntyre (1) (3) (5) (6) Independent Businessman Calgary, Alberta Lyle G. Stevens Senior Vice-President, Exploitation Jeff W. Wilson Senior Vice-President, Exploration Mary-Jo E. Case Vice-President, Land James S. Palmer, C.M., A.O.E., Q.C. (1) (3 – Chair) (5) (6) Chairman and Partner, Burnet, Duckworth & Palmer LLP Calgary, Alberta Randall S. Davis Vice-President, Financial Accounting & Controls Eldon R. Smith, M.D. (1) (3) (4) (6 – Chair) Professor Emeritus and Former Dean, Faculty of Medicine, University of Calgary Calgary, Alberta David A. Tuer (1) (2) (4) (5 – Chair) President, Value Creations Inc. Calgary, Alberta (1) 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. (2) Audit Committee member (3) Compensation Committee member (4) Nominating and Corporate Governance Committee member (5) Reserves Committee member (6) Health, Safety and Environment Committee member 104 Corporate Information 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 Calgary, Alberta Ryder Scott Company Calgary, Alberta Sproule Associates Limited Calgary, Alberta STOCK LISTING The Toronto Stock Exchange CNQ CNQ.U (Denotes trading in US funds) The New York Stock Exchange CNQ Printed in Canada by Sundog Printing. Principal photography by Gary Campbell. Additional photography by Christine Flatt, Stephan C. Dragomir, Edwin Herrenschmidt, Rolf Karis and Canadian Natural team members. CORPORATE OFFICES HEAD OFFICE Canadian Natural Resources Limited 2500, 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 Facsimile: (403) 517-7370 Email: ir@cnrl.com INTERNATIONAL OFFICE CNR International (U.K.) Limited St. Magnus House, Guild Street Aberdeen AB11 6NJ Scotland CORPORATE GOVERNANCE 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. Canadian Natural, as a “foreign private issuer” in the United States, may rely on home jurisdiction listing standards for compliance with most of the New York Stock Exchange (“NYSE”) Corporate Governance Listing Standards but must disclose any signiﬁ cant differences between its corporate governance practices and those required for U.S. companies listed on the NYSE. Toronto Stock Exchange (“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 and material revisions to such plans. Canadian Natural follows TSX rules with respect to shareholder approval of equity compensation plans. Canadian Natural has included as exhibits to its Annual Report on Form 40-F for the 2005 ﬁ scal year ﬁ led with the United States Securities and Exchange Commission certiﬁ cates of the Chief Executive Ofﬁ cer and Chief Financial Ofﬁ cer certifying the quality of its public disclosure. Corporate Information IMPORTANT DATES PRESS RELEASE FIRST QUARTER 2006 Thursday, May 4, 2006 ANNUAL GENERAL MEETING Thursday, May 4, 2006 PRESS RELEASE SECOND QUARTER 2006 Wednesday, August 2, 2006 PRESS RELEASE THIRD QUARTER 2006 Wednesday, November 1, 2006 CANADIAN NATURAL RESOURCES LIMITED 2500, 855 - 2 Street SW Calgary, Alberta Canada T2P 4J8 Phone: 403.517.6700 403.517.7350 Fax: www.cnrl.com You can ﬁ nd PDF versions of this and other publications from Canadian Natural at www.cnrl.com You can request documents by calling our head ofﬁ ce or via email: ir@cnrl.com

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