EX-99 4 ex-3form40f_2004.txt EXHIBIT 3 EXHIBIT 3 --------- 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS MANAGEMENT'S DISCUSSION AND 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 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 the Company "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: the general economic and business conditions which will, among other things, impact demand for and market prices of the Company's products; the foreign currency exchange rates; the economic conditions in the countries and regions in which the Company conducts business; the political uncertainty, including actions of or against terrorists, insurgent groups or other conflict including conflict between states; the industry capacity; the ability of the Company to implement its business strategy, including exploration and development activities; the impact of competition, availability and cost of seismic, drilling and other equipment; the ability of the Company to complete its capital programs; the ability of the Company to transport its products to market; the potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the operating hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas; the availability and cost of financing; the success of exploration and development activities; the timing and success of integrating the business and operations of acquired companies; the production levels; the uncertainty of reserve estimates; the actions by governmental authorities; the government regulations and the expenditures required to comply with them (especially safety and environmental laws and regulations); the 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 upon other factors, and management'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 are made, no assurances can be given as to future results, levels of activity and achievements. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The Company assumes no obligation to update forward-looking statements should circumstances or management'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 oil and gas industry, such as cash flow, cash flow per share 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 the performance of the Company and its business segments. 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, 2004. 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 17 to the consolidated financial statements. All dollar amounts are referenced in Canadian dollars, except where noted otherwise. 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 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 2004 financial results compared to 2003, unless otherwise indicated. In addition, this discussion details the Company's capital program and outlook for 2005. The fourth quarter discussion and analysis was included in the Company's fourth quarter press release. This MD&A is dated February 18, 2005. CANADIAN NATURAL 39 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT OBJECTIVE AND STRATEGY The Company's objective is to increase cash flow, crude oil and natural gas production, reserves and net asset value on a per common share basis through the development of its existing crude oil and natural gas properties and through the discovery and acquisition of new reserves. The Company accomplishes this by having a defined growth and value enhancement plan for each of its products and segments. The Company takes a measured approach to growth and investments and focuses on creating long-term shareholder wealth. The Company effectively allocates its capital by maintaining: o Balance between its products, namely natural gas, light crude oil, Pelican Lake crude oil (1), primary heavy crude oil and thermal heavy crude oil; o Balance between near-, mid- and long-term projects; o Balance between acquisitions, exploitation and exploration; and o Balance between sources of debt and a strong balance sheet. (1) Pelican Lake crude oil is 14-17 degrees API oil, but receives medium quality crude netbacks due to low operating costs and low royalty rates. The Company has expanded its hedging program in an effort to reduce the risk of volatility in commodity price markets and to underpin the Company's cashflow through the Horizon Oil Sands Project ("Horizon Project") construction period. The Company's crude oil marketing strategy includes displacing medium sour crude oil from PADD II, supporting and participating in pipeline additions, encouraging the development of projects that add conversion capacity, and blending strategy. Cost control is central to the Company's strategy. By controlling costs consistently throughout all industry cycles, the Company is able to achieve continued growth. Cost control is attained by area knowledge, by core area domination and by operating at a high working interest. Strategic accretive acquisitions are a key component of the Company's strategy. The Company has used excess cash flows derived from higher than expected commodity prices to selectively acquire properties generating future cash flows in its core regions. These targeted acquisitions provide relatively quick repayment of initial investments and will provide additional free cash flow during the construction years of the Horizon Project while still achieving targeted returns. The acquisitions of the Petrovera Partnership ("Petrovera") and natural gas properties in North America and the acquisition of properties in the central North Sea meet these reinvestment criteria and further enhance the Company's abilities to complete the Horizon Project. This expansion of the conventional asset base also helps reduce the sole project risk exposure associated with this major oil sands development project. The Company is committed to maintaining its strong financial position throughout construction of the Horizon Project. The Company has built the necessary financial capacity to complete the Horizon Project while at the same time not compromising delivery of low-risk crude oil and natural gas growth opportunities. The year ended December 31, 2004, was another successful year in the execution of the Company's strategy. Highlights are as follows: o Achieved record levels of net earnings; o Achieved record levels of cash flow; o Achieved record levels of natural gas and crude oil and NGLs production; o Achieved the Company's annual production guidance for both natural gas and crude oil and NGLs; o Completed four strategic acquisitions including: o the acquisition of Petrovera; o the acquisition of natural gas assets located in the Company's core region of Northeast British Columbia and an extension of its core region in the Foothills area of Northwest Alberta; o the acquisition of light crude oil producing properties in the Central North Sea; o the acquisition of certain natural gas properties located in Alberta, British Columbia and Saskatchewan; o Commenced production from a new phase of the Primrose in-situ thermal crude oil development; o Filed a public disclosure document for regulatory approval of the Primrose East project; o Received regulatory approvals for the Horizon Project from the Alberta Energy and Utilities Board as well as the Alberta Provincial Cabinet and the Canadian Federal Cabinet; o Completed the subdivision of its Common Shares on the basis of two for one; o Increased the quarterly dividend by 33% to $0.10 per common share; and o Purchased 873,400 common shares for a total cost of $33 million under the Company's Normal Course Issuer Bid. 40 CANADIAN NATURAL 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS NET EARNING AND CASH FLOW FROM OPERATIONS
FINANCIAL HIGHLIGHTS ($ millions, except per common share amounts) 2004 2003(1) 2002(1) ------------------------------------------------------------------ ------- ------- ------- Revenue, before royalties $ 7,547 $ 6,155 $ 4,459 Net earnings $ 1,405 $ 1,403 $ 539 Per common share - basic (2) $ 5.24 $ 5.23 $ 2.11 - diluted (2) $ 5.20 $ 5.06 $ 2.04 Cash flow from operations (4) $ 3,769 $ 3,160 $ 2,254 Per common share - basic (2) $ 14.06 $ 11.77 $ 8.82 - diluted (2) $ 13.98 $ 11.53 $ 8.50 Capital expenditures, net of dispositions (3) $ 4,633 $ 2,506 $ 4,069
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Restated to reflect two-for-one share split in May 2004. (3) In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as Petrovera, for $471 million. Strategically, the acquisition fit with the Company's objective of dominating its core regions and related infrastructure. The Company achieved cost reductions through synergies with its existing facilities, including additional throughput in its 100% owned ECHO Pipeline. The acquisition is included in the results of operations commencing February 2004. In 2002, the Company paid cash of $850 million and issued 20,016,436 common shares to acquire all of the issued and outstanding common shares of Rio Alto Exploration Ltd. ("Rio Alto") by way of a plan of arrangement. This was a strategic acquisition as it increased the Company's natural gas production and added a new natural gas core region in Northwest Alberta. The Rio Alto acquisition is included in the results of operations commencing July 2002. (4) Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items. The Company evaluates its performance and that of its business segments based on net earnings and cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company's ability and the ability of its business segments to generate the cash flow necessary to fund future growth through capital investment and to repay debt.
($ millions) 2004 2003 2002 ------------------------------------------ ------- ------- ------- Net earnings $ 1,405 $ 1,403 $ 539 Non-cash items: Depletion, depreciation and amortization 1,769 1,509 1,298 Asset retirement obligation accretion 51 62 68 Stock-based compensation 249 200 - Unrealized risk management activities (40) - - Unrealized foreign exchange gain (94) (343) (36) Deferred petroleum revenue tax (recovery) (45) (9) 10 Future income tax 474 338 375 ------- ------- ------- Cash flow from operations $ 3,769 $ 3,160 $ 2,254 ======= ======= =======
The Company achieved record levels of net earnings, cash flow from operations and production in 2004 as a result of strong operational performance combined with strong commodity prices. The strong operating results are attributable to the Company following its defined growth strategy and to the strong asset base the Company has developed over time through organic growth and accretive acquisitions. Net earnings increased in 2004 to $1,405 million ($5.24 per common share), up from $1,403 million ($5.23 per common share) in 2003 (2002 - $539 million or $2.11 per common share). The increase in net earnings in 2004 is primarily due to higher commodity prices and higher production volumes. These increases were offset by increased depletion, depreciation and amortization expense, increased stock-based compensation expense and decreased foreign exchange gains in 2004. In addition, net earnings were also impacted by the Company's risk management activities as a result of an expanded hedging program (see risk management activities and liquidity and capital resources) and one-time non recurring tax rate reductions. Cash flow from operations reached record levels in 2004. Cash flow from operations increased 19% to $3,769 million ($14.06 per common share), up from $3,160 million ($11.77 per common share) in 2003 (2002 - $2,254 million or $8.82 per common share). The increase in cash flow from operations resulted primarily from higher product prices and increased production volumes. In 2004, the Company's average price per barrel of crude oil and NGLs increased 16% to $37.99 from $32.66 in 2003 (2002 - $31.22). The Company's average natural gas price increased 5% to $6.50 per mcf from $6.21 per mcf in 2003 (2002 - $3.77 per mcf). Production volumes before royalties increased 12% to a record 513,835 boe/d, up from 458,814 boe/d in 2003 (2002 - 420,722 boe/d). The increase in production volumes was a result of organic growth and accretive acquisitions. Production of crude oil and NGLs before royalties increased 17% to 282,489 bbl/d, up from 242,392 bbl/d in 2003 (2002 -215,335 bbl/d). Natural gas production before royalties increased 7% to 1,388 mmcf/d, up from 1,299 mmcf/d in 2003 (2002 - 1,232 mmcf/d). CANADIAN NATURAL 41 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT
OPERATING HIGHLIGHTS 2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl, except daily production) Daily production, before royalties (bbl/d) 282,489 242,392 215,335 Sales price (1) $ 37.99 $ 32.66 $ 31.22 Royalties 3.16 2.77 3.16 Production expense 10.05 10.28 8.45 ------------ --------- -------- Netback $ 24.78 $ 19.61 $ 19.61 ------------ --------- -------- NATURAL GAS ($/mcf, except daily production) Daily production, before royalties (mmcf/d) 1,388 1,299 1,232 Sales price (1) $ 6.50 $ 6.21 $ 3.77 Royalties 1.35 1.32 0.78 Production expense 0.67 0.60 0.57 ------------ --------- -------- Netback $ 4.48 $ 4.29 $ 2.42 ------------ --------- -------- BARREL OF OIL EQUIVALENT ($/boe, except daily production) Daily production, before royalties (boe/d) 513,835 458,814 420,722 Sales price (1) $ 38.45 $ 34.84 $ 27.02 Royalties 5.37 5.20 3.91 Production expense 7.35 7.15 5.99 ------------ --------- -------- Netback $ 25.73 $ 22.49 $ 17.12 ============ ========= ========
(1) Including transportation costs and excluding risk management activities. BUSINESS ENVIRONMENT
2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- WTI benchmark price (US$/bbl) $ 41.43 $ 31.02 $ 26.11 Dated Brent benchmark price (US$/bbl) $ 38.28 $ 28.83 $ 25.01 Differential to LLB blend (US$/bbl) $ 13.44 $ 8.55 $ 6.50 Condensate benchmark price (US$/bbl) $ 41.62 $ 31.42 $ 26.00 NYMEX benchmark price (US$/mmbtu) $ 6.09 $ 5.44 $ 3.25 AECO benchmark price (C$/GJ) $ 6.43 $ 6.35 $ 3.86 US/Canadian dollar average exchange rate (US$) 0.7683 0.7135 0.6368 ====== ====== ======
World crude oil prices remained strong in 2004 due to the strong growth in world-wide demand, particularly in the United States and Asia. World crude oil prices have also been impacted by geopolitical uncertainty in several areas of the world, resulting in concerns around the supply of crude oil. World crude oil prices have been further impacted by weather related issues causing production disruptions in the United States Gulf Coast. West Texas Intermediate ("WTI") averaged US$41.43 per bbl for the year ended December 31, 2004, up 34% compared to US$31.02 per bbl in 2003 (2002 - US$26.11 per bbl). The impact of the higher WTI prices on the Company's heavier crude oil production was mitigated by wider heavy crude oil differentials, which increased 57% to US$13.44 per bbl in 2004, up from US$8.55 per bbl in 2003 (2002 - US$6.50 per bbl). Realized crude oil prices were also impacted by the strengthening Canadian dollar. North American natural gas prices remained strong due to concerns around supply and the impact of higher crude oil prices. NYMEX natural gas prices increased 12% to average US$6.09 per mmbtu in 2004, up from US$5.44 per mmbtu in 2003 (2002 - US$3.25 per mmbtu). AECO natural gas prices increased 1 % to average $6.43 per GJ in 2004, up from $6.35 per GJ in 2003 (2002 - $3.86 per GJ). 42 CANADIAN NATURAL 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS
REVENUE, BEFORE ROYALTIES PRODUCT PRICES (1) 2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS ($/bbl) North America 33.16 $ 29.40 $ 28.77 North Sea 51.37 $ 42.00 $ 40.32 Offshore West Africa 49.05 $ 36.47 $ 40.10 Company average 37.99 $ 32.66 $ 31.22 NATURAL GAS ($/mcf) North America 6.61 $ 6.34 $ 3.79 North Sea 3.73 $ 3.03 $ 2.75 Offshore West Africa 5.25 $ 4.37 $ 4.82 Company average 6.50 $ 6.21 $ 3.77 PERCENTAGE OF REVENUE (excluding midstream revenue) Crude oil and NGLs 54% 50% 58% Natural gas 46% 50% 42% ==== ==== ====
(1) Including transportation costs and excluding risk management activities. Realized crude oil prices increased 16% to average $37.99 per bbl in 2004, up from $32.66 per bbl in 2003 (2002 - $31.22 per bbl). The increase in realized crude oil prices is a result of higher benchmark crude oil prices. The Company's realized natural gas price increased 5% to average $6.50 per mcf in 2004, up from $6.21 per mcf in 2003 (2002 - $3.77 per mcf). NORTH AMERICA North America realized crude oil prices increased 13% to average $33.16 per bbl in 2004, up from $29.40 per bbl in 2003 (2002 - $28.77 per bbl). The increase in the realized crude oil price is due mainly to higher world crude oil prices, partially offset by wider heavy crude oil differentials and the stronger Canadian dollar. The Company continues to focus on its crude oil marketing strategy, which includes development of a blending strategy, supporting pipeline projects that will provide capacity to transport crude oil to new markets, and working with PADD II refiners 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 mbbl/d. The Company is contributing 123 mbbl/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 oil with premium quality asphalt characteristics. The new blend has an API of 19-22 degrees and is expected to grow, with the potential to become a new benchmark for North American markets in addition to WTI. The Company also continues to work with refiners to advance expansion of heavy crude oil conversion capacity, and is working with pipeline companies to develop new capacity to the Canadian west coast where crude cargos can be sold on a world-wide basis. North America realized natural gas prices increased 4% to average $6.61 per mcf in 2004, up from $6.34 per mcf in 2003 (2002 - $3.79 per mcf). The increase in natural gas pricing is due to the concerns around supply and the impact of higher crude oil prices. A comparison of the price received for the Company's North America production is as follows:
2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- Wellhead price(1) Light crude oil and NGLs (C$/bbl) $ 45.90 $ 37.59 $ 34.92 Pelican Lake crude oil (C$/bbl) $ 32.12 $ 28.05 $ 27.56 Primary heavy crude oil (C$/bbl) $ 28.99 $ 26.21 $ 27.06 Thermal heavy crude oil (C$/bbl) $ 29.00 $ 25.55 $ 25.70 Natural gas (C$/mcf) $ 6.61 $ 6.34 $ 3.79 ======= ======= =======
(1) Including transportation costs and excluding risk management activities. NORTH SEA North Sea realized crude oil prices increased 22% to average $51.37 per bbl in 2004, up from $42.00 per bbl in 2003 (2002 - $40.32 per bbl) due to higher world crude oil prices. OFFSHORE WEST AFRICA Offshore West Africa realized crude oil prices increased 34% to average $49.05 per bbl in 2004, up from $36.47 per bbl in 2003 (2002 - $40.10 per bbl) due to higher world crude oil prices. 43 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT ANALYSIS OF CHANGES IN REVENUE, BEFORE ROYALTIES
Changes due to CHANGES DUE TO -------------------------------------------------- ----------------------------------- ($ millions) 2002 Volumes Prices Other 2003 VOLUMES PRICES OTHER 2004 ------------------------------------------------------------------------------------------------------------------- NORTH AMERICA Crude oil and NGLs $ 1,854 $ 55 $ 44 $ - $ 1,953 $ 342 $ 283 $ - $ 2,578 Natural gas 1,865 56 1,147 - 3,068 207 126 - 3,401 ------- ------- ------- --- ------- ------- ------- --- ------- 3,719 111 1,191 - 5,021 549 409 - 5,979 ------- ------- ------- --- ------- ------- ------- --- ------- NORTH SEA Crude oil and NGLs 592 265 16 - 873 123 227 - 1,223 Natural gas 28 19 33 - 80 5 9 - 94 ------- ------- ------- --- ------- ------- ------- --- ------- 620 284 49 - 953 128 236 - 1,317 ------- ------- ------- --- ------- ------- ------- --- ------- OFFSHORE WEST AFRICA Crude oil and NGLs 100 56 (15) - 141 13 54 - 208 Natural gas 2 13 (1) - 14 (1) 1 - 14 ------- ------- ------- --- ------- ------- ------- --- ------- 102 69 (16) - 155 12 55 - 222 ------- ------- ------- --- ------- ------- ------- --- ------- SUBTOTAL Crude oil and NGLs 2,546 376 45 - 2,967 478 564 - 4,009 Natural gas 1,895 88 1,179 - 3,162 211 136 - 3,509 ------- ------- ------- --- ------- ------- ------- --- ------- 4,441 464 1,224 - 6,129 689 700 - 7,518 MIDSTREAM 52 - - 9 61 - - 7 68 OTHER - - - - - - - 1 1 INTERSEGMENT (34) - - (1) (35) - - (5) (40) ------- ------- ------- --- ------- ------- ------- --- ------- ELIMINATIONS (1) TOTAL $ 4,459 $ 464 $ 1,224 $ 8 $ 6,155 $ 689 $ 700 3 $ 7,547 ------- ------- ------- --- ------- ------- ------- --- -------
(1) Eliminates internal transportation and electricity charges. Revenue rose 23% to $7,547 million in 2004, up from $6,155 million in 2003 (2002 - $4,459 million). In 2004, 20% of the Company's crude oil and natural gas revenue was generated outside of North America, up from 18% in 2003 (2002 - 16%). North Sea accounted for 17% of revenue in 2004 and 16% in 2003 (2002 - 14%), and Offshore West Africa accounted for 3% of revenue in 2004 and 2% in 2003 (2002 - 2%). The Company's production composition, before royalties, is as follows: DAILY PRODUCTION, BEFORE ROYALTIES
2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 206,225 174,895 169,675 North Sea 64,706 56,869 38,876 Offshore West Africa 11,558 10,628 6,784 ------- ------- ------- 282,489 242,392 215,335 ------- ------- ------- NATURAL GAS (mmcf/d) North America 1,330 1,245 1,204 North Sea 50 46 27 Offshore West Africa 8 8 1 ------- ------- ------- 1,388 1,299 1,232 ------- ------- ------- TOTAL BARREL OF OIL EQUIVALENT (boe/d) 513,835 458,814 420,722 ------- ------- ------- PRODUCT MIX Light crude oil and NGLs 24% 25% 21% Pelican Lake crude oil 4% 5% 7% Primary heavy crude oil 19% 15% 14% Thermal heavy crude oil 8% 8% 9% Natural gas 45% 47% 49% ------- ------- -------
44 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS DAILY PRODUCTION, NET OF ROYALTIES
2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- CRUDE OIL AND NGLS (bbl/d) North America 180,011 152,444 149,485 North Sea 64,598 56,928 36,654 Offshore West Africa 11,221 10,314 6,554 ------- ------- ------- 255,830 219,686 192,693 ------- ------- ------- NATURAL GAS (mmcf/d) North America 1,048 976 949 North Sea 50 46 27 Offshore West Africa 7 8 1 ------- ------- ------- 1,105 1,030 977 ------- ------- ------- TOTAL BARREL OF OIL EQUIVALENT (boe/d) 440,022 391,361 355,611 ------- ------- -------
Daily production and per barrel statistics are presented throughout the MD&A on a "before royalty" or "gross" basis. Production net of royalties is presented above for information purposes only. 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. The Company achieved record levels of production on a barrel of oil equivalent basis in 2004. Production before royalties on a barrel of oil equivalent basis increased 12% to average 513,835 boe/d in 2004, up from 458,814 boe/d in 2003 (2002 - 420,722 boe/d). The production volumes increased as a result of the Company's successful capital expenditure program and the acquisition of certain resource properties in the Company's North America and North Sea segments. Total crude oil and NGLs production before royalties increased 17% or 40,097 bbl/d to average 282,489 bbl/d, up from 242,392 bbl/d in 2003 (2002 - 215,335 bbl/d). Crude oil and NGLs production before royalties in 2004 increased from the previous year in all segments and was in line with production guidance provided. Natural gas production before royalties continues to represent the Company's largest product offering, accounting for 45% of the Company's total production in 2004 compared to 47% of total production in 2003 (2002 - 49%). Natural gas production before royalties increased 7% or 89 mmcf/d to average 1,388 mmcf/d, up from 1,299 mmcf/d in 2003 (2002 - 1,232 mmcf/d). Natural gas production was in line with production guidance provided. The Company expects annual production levels before royalties in 2005 to average 1,448 to 1,510 mmcf/d of natural gas and 307 to 335 mbbl/d of crude oil and NGLs. First quarter 2005 production guidance before royalties is 1,400 to 1,482 mmcf/d of natural gas and 269 to 290 mbbl/d of crude oil and NGLs. NORTH AMERICA Crude oil and NGLs production before royalties in North America increased 18% or 31,330 bbl/d to average 206,225 bbl/d in 2004, up from 174,895 bbl/d in 2003 (2002 - 169,675 bbl/d) due to the development of the Primrose thermal crude oil project and accretive acquisitions. North American natural gas production before royalties in 2004 increased 7% or 85 mmcf/d to average 1,330 mmcf/d, up from 1,245 mmcf/d in 2003 (2002 - 1,204 mmcf/d). North American production of natural gas increased as a result of organic growth and accretive property acquisitions. Production of natural gas was impacted by the shut in of 11 mmcf/d of natural gas in the Athabasca Wabiskaw-McMurray oil sands area effective July 1, 2004. NORTH SEA Crude oil production before royalties from the North Sea increased 14% or 7,837 bbl/d to average 64,706 bbl/d in 2004, up from 56,869 bbl/d in 2003 (2002 - 38,876 bbl/d). The increase in production was due to the ongoing drilling, recompletion and waterflood optimization program at the Ninian and Murchison Fields and the acquisition of light crude oil producing properties in the Central North Sea in the third quarter of 2004. Crude oil production before royalties in the fourth quarter was down primarily due to an unplanned extended shutdown on the Ninian North Platform. The shutdown was required to repair a power turbine used to drive water injection resulting in a loss of pressure to the reservoir. Remedial work was completed in early 2005 and production is recovering. Natural gas production before royalties in the North Sea increased 9% or 4 mmcf/d to average 50 mmcf/d in 2004, up from 46 mmcf/d in 2003 (2002 - 27 mmcf/d). The increase in production was due to the acquisition of properties in the Central North Sea in the third quarter of 2004 and the increased working interests acquired in the Banff Field during 2003. The increase was partially offset by the commencement of the natural gas reinjection program in the Banff Field in the fourth quarter of 2004. Despite some delays and production interruptions during commissioning, results to date are positive with full production benefit expected to commence during the second quarter of 2005. Natural gas production in the North Sea is expected to decline in 2005 due to the natural gas reinjection program in the Banff Field. 45 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT OFFSHORE WEST AFRICA Offshore West Africa crude oil production before royalties for the year ended December 31, 2004 increased 9% or 930 bbl/d to average 11,558 bbl/d, up from 10,628 bbl/d in 2003 (2002 - 6,784 bbl/d) due to the perforation of the upper zone of the East Espoir Field in the third quarter of 2003 and the completion of the fourth water injection well and two additional producing wells during 2003. Natural gas production before royalties in Offshore West Africa remained constant at 8 mmcf/d in 2004 and 2003 (2002 - 1 mmcf/d). ROYALTIES
2004 2003 2002 --------------------------------------------------------------------------------- CRUDE OIL AND NGLs ($/bbl) North America $ 4.21 $ 3.79 $ 3.42 North Sea $ 0.08 $ (0.03) $ 2.30 Offshore West Africa $ 1.43 $ 1.08 $ 1.35 Company average $ 3.16 $ 2.77 $ 3.16 NATURAL GAS ($/mcf) North America $ 1.40 $ 1.38 $ 0.80 North Sea $ - $ - $ - Offshore West Africa $ 0.15 $ 0.13 $ 0.15 Company average $ 1.35 $ 1.32 $ 0.78 COMPANY AVERAGE ($/BOE) $ 5.37 $ 5.20 $ 3.91 PERCENTAGE OF REVENUE(1) Crude oil and NGLs 8% 9% 10% Natural gas 21% 21% 21% Boe 14% 15% 14%
(1) Including transportation costs and excluding risk management activities. NORTH AMERICA Crude oil and NGLs royalties in North America increased to $4.21 per bbl, up from $3.79 per bbl in 2003 (2002 - $3.42 per bbl) due to higher benchmark crude oil prices. Natural gas royalties in North America increased to $1.40 per mcf, up from $1.38 per mcf in 2003 (2002 - $0.80 per mcf). Natural gas royalties as a percentage of revenue fluctuate as a result of fluctuations in natural gas prices and the strong correlation of royalties to natural gas prices. NORTH SEA North Sea crude oil royalties increased to $0.08 per bbl, up from a recovery of $(0.03) per bbl in 2003 (2002 - $2.30 per bbl). 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 crude oil royalties increased to $1.43 per bbl, up from $1.08 per bbl in 2003 (2002 - $1.35 per bbl) due to fluctuations in realized crude oil prices. Offshore West Africa production is governed by the terms of the Production Sharing Contract ("PSC"). Under the PSC, revenues are divided into cost recovery revenue and profit revenue. Cost recovery revenue allows the Company to recover the capital and operating costs carried by the Company on behalf of the Government State Oil Company. These revenues are reported as sales revenue. Profit revenue is allocated to the joint venture partners in accordance with their respective equity interests, after a portion has been allocated to the Government. The Government's share of revenue attributable to the Company's equity interest is reported as either royalty expense or current income tax expense in accordance with the PSC. 46 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS PRODUCTION EXPENSE
2004 2003 2002 ----------------------------------------------------------------- CRUDE OIL AND NGLs ($/bbl) North America $ 8.94 $ 9.14 $ 6.73 North Sea $ 14.03 $ 14.07 $ 15.06 Offshore West Africa $ 7.59 $ 8.68 $ 13.63 Company average $ 10.05 $ 10.28 $ 8.45 NATURAL GAS ($/mcf) North America $ 0.62 $ 0.57 $ 0.55 North Sea $ 2.07 $ 1.33 $ 1.53 Offshore West Africa $ 1.33 $ 1.39 $ 1.81 Company average $ 0.67 $ 0.60 $ 0.57 COMPANY AVERAGE ($/BOE) $ 7.35 $ 7.15 $ 5.99
Production expense increased to $7.35 per boe in 2004, up from $7.15 per boe in 2003 (2002 - $5.99 per boe). Crude oil and NGLs production expense decreased to $10.05 per bbl in 2004, down from $10.28 per bbl in 2003 (2002 - $8.45 per bbl). Natural gas production expense for the year 2004 increased to $0.67 per mcf, up from $0.60 per mcf in 2003 (2002 - $0.57 per mcf). NORTH AMERICA North American crude oil and NGLs production expense decreased 2% to average $8.94 per bbl, down from $9.14 per bbl in 2003 (2002 - $6.73 per bbl). The decrease was primarily due to the impact of a lower steam oil ratio for the Company's thermal heavy crude oil operations, resulting in a lower cost per barrel for fuel used in the generation of steam. North American natural gas production expense per mcf increased 9% to average $0.62 per mcf, up from $0.57 per mcf in 2003 (2002 - $0.55 per mcf). The increase is partly due to increased activity in the oil and gas sector in reaction to higher commodity prices, which resulted in higher production expense, especially as the labour market tightened, and partly due to increased production in certain areas such as Northeast British Columbia where the Company is incurring higher costs associated with third party processing and gathering. In addition, the cost of steel products increased in 2004 due to increased global demand. NORTH SEA North Sea crude oil production expense decreased in 2004 to $14.03 per bbl, down from $14.07 per bbl in 2003 (2002 - $15.06 per bbl). North Sea crude oil production expense varied on a per barrel basis due to the timing of maintenance work and the changes in production volumes on a relatively fixed cost base. OFFSHORE WEST AFRICA Offshore West Africa crude oil production expense decreased to $7.59 per bbl, down from $8.68 per bbl in 2003 (2002 - $13.63 per bbl), resulting from production increases in the Espoir Field. The Espoir Field commenced operations in the first quarter of 2002. Offshore West Africa crude oil production expenses are largely fixed in nature and therefore fluctuate on a per barrel basis from the comparable periods due to changes in production from the Espoir Field. MIDSTREAM
($ MILLIONS) 2004 2003 2002 ----------------------------------------------------------- Revenue $68 $61 $52 Production expense 20 $15 $14 Midstream cash flow 48 $46 $38 Depreciation 7 $ 7 $ 8 Segment earnings before taxes $41 $39 $30
The Company's midstream assets consist of three crude oil pipeline systems and an 84-megawatt cogeneration plant at Primrose where the Company has a 50% working interest. Approximately 80% of the Company's heavy crude oil production was transported to the 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 transport its own production volumes at reduced costs compared to other transportation alternatives as well as earn third party revenue. This transportation control enhances the Company's ability to control the full range of costs associated with the development and marketing of its heavy crude oil. 47 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Revenue from the midstream assets increased 11% to $68 million, up from $61 million in 2003 (2002 - $52 million). The increase in revenue, operating cash flow and segment earnings before taxes was due to the expansion of the ECHO Pipeline. The expansion of the ECHO Pipeline was completed in October 2003 and increased capacity to 72 mbbl/d from 58 mbbl/d. DEPLETION, DEPRECIATION AND AMORTIZATION(2)
($ millions, except per boe amounts) 2004 2003(1) 2002(1) ------------------------------------------------------------------------------------------------------------------------------ North America $ 1,444 $ 1,209 $ 1,022 North Sea 265 $ 252 $ 188 Offshore West Africa 53 $ 41 $ 80 Expense $ 1,762 $ 1,502 $ 1,290 $/boe $ 9.37 $ 8.96 $ 8.40 ========== ========== =========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) DD&A excludes depreciation on midstream assets. Depletion, depreciation and amortization ("DD&A") increased in total and per boe to $1,762 million or $9.37 per boe, up from $1,502 million or $8.96 per boe in 2003 (2002 - $1,290 million or $8.40 per boe). The increase in DD&A was due to higher finding and development costs associated with natural gas exploration in North America, the allocation of the acquisition costs associated with recent acquisitions, the fair value of future abandonment costs associated with the acquisition of additional properties in the North Sea, and higher costs to develop the Company's proved undeveloped reserves. In 2003, DD&A included the write-off of $12 million of costs associated with the Company's exploration activity in offshore France. In 2002, DD&A included the write-off of $51 million as a result of the Company's decision to exit from its interests in Block 19, Angola, and from the Aje Field, Nigeria. ASSET RETIREMENT OBLIGATION ACCRETION
($ millions, except per boe amounts) 2004 2003(1) 2002(1) --------------------------------------------------------------------------------------------------- North America $ 28 $ 26 $ 20 North Sea $ 22 $ 36 $ 48 Offshore West Africa $ 1 $ - $ - Expense $ 51 $ 62 $ 68 $/boe $ 0.27 $ 0.37 $ 0.44 ======== ======== ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). Accretion expense is the increase in the carrying amount of the asset retirement obligation due to the passage of time. ADMINISTRATION EXPENSE
($ millions, except per boe amounts) 2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- Gross cost $ 315 $ 262 $ 147 $/boe $ 1.68 $ 1.57 $ 0.96 Net expense $ 115 $ 87 $ 61 $/boe $ 0.61 $ 0.52 $ 0.40 =========== ======== ========
Gross administration expense increased to $1.68 per boe, up from $1.57 per boe in 2003 (2002 - $0.96 per boe) mainly due to higher staffing levels associated with the Company's expanding asset base and costs associated with the Horizon Project. Gross administration expense also increased as a result of higher costs related to the assumption of operatorship of certain fields in the North Sea in 2003. Net administration expense, after operator recoveries and capitalized overhead relating to exploration and development in the North Sea and Offshore West Africa as well as the Horizon Project, increased to $0.61 per boe in 2004, up from $0.52 per boe in 2003 (2002 - $0.40 per boe). 48 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS STOCK-BASED COMPENSATION
($ millions, except per boe amounts) 2004 2003 2002 -------------------------------------------------------------------------------------------------------------------------------- Stock option plan $ 249 $ 200 $ - Share bonus plan 10 $ - $ - Stock-based compensation expense $ 259 $ 200 $ - $/boe $ 1.37 $ 1.20 $ - =========== ======== =======
The Company's Stock Option Plan (the "Option Plan") provides current employees, officers and directors (the "option holders") with the right to elect to receive common shares or a direct cash payment in exchange for options surrendered. The Option Plan balances the need for a long-term compensation program to retain employees with reducing the impact of dilution on current Shareholders and the reporting of the expense associated with stock options. Transparency of the cost of the Option Plan is increased since changes in the fair value of outstanding stock options are expensed. The cash payment feature provides option holders with substantially the same benefits and allows them to realize the value of their options through a simplified administration process. The Company has recorded a liability at December 31, 2004 of $323 million compared to $171 million at December 31, 2003 for expected cash settlements of stock options based on the fair value of the outstanding stock options (the difference between the exercise price of the stock options and the market price of the Company's common shares). The liability is revalued to reflect changes in the market price of the Company's common shares and the net change is recognized in net earnings. The stock-based compensation expense relating to the Company's Option Plan in 2004 is $249 million ($168 million after tax), up from $200 million ($136 million after tax) in 2003. In 2004, the Company paid $80 million for stock options surrendered for cash settlement compared to $31 million in 2003. The Share Bonus Plan incorporates share ownership in the Company by its employees without the granting of stock options or the dilution of current Shareholders. Under the plan, a cash bonus may be awarded based on the Company's and the employee's performance and 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. In 2004, the Company recognized $10 million ($6 million after tax) of compensation expense under the Share Bonus Plan. INTEREST EXPENSE
($ millions, except per boe amounts and interest rates) 2004 2003(1) 2002(1) -------------------------------------------------------------------------------------------------------------------------- Interest expense $ 189 $ 201 $ 203 $/boe $ 1.01 $ 1.20 $ 1.26 Average effective interest rate 5.2% 5.8% 5.5% === === ===
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). Interest expense decreased to $189 million in 2004, down from $201 million in 2003 (2002 - $203 million) due mainly to a lower average effective interest rate of 5.2%, down from 5.8% in 2003 (2002 - 5.5%). In addition, the strengthening Canadian dollar reduced the Canadian equivalent interest expense on the Company's US dollar denominated debt. The Company continues to benefit from the lower short-term interest rates as its fixed-rate debt accounts for only 43% of total debt outstanding after interest rates swaps (see note 12 to the consolidated financial statements) as at December 31, 2004 (2003 - 32%, 2002 - 40%). Interest expense was impacted by the Company prospectively adopting the Canadian Institute of Chartered Accountants' ("CICA") Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments." As a result of the adoption of this accounting guideline, $32 million of realized gains on certain of its fixed to floating interest rate swaps are included in risk management activities in 2004 (2003 - $35 million, 2002 - $34 million). Interest expense decreased on a total and boe basis in 2004 from 2003 mainly due to lower borrowing rates. 49 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT RISK MANAGEMENT ACTIVITIES On January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments". Financial instruments that do not qualify as hedges under the Guideline or are not designated as hedges are recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recognized in net earnings. The Company utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are not used for trading or speculative purposes. 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. The Company also enters into foreign currency denominated financial instruments to manage future US dollar denominated crude oil and natural gas sales. 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 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 interest rate contracts not designated as hedges are included in risk management activities. The Company enters into cross currency swap agreements to manage its fixed to floating interest rate mix on 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 long-term 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 gain or loss is recognized in net earnings. Adoption of this Guideline and EIC 128 had the following effects on the Company's consolidated financial statements:
($ millions) 2004 2003 2002 ------------------------------------------------------------------------------------------------------------------------------ REALIZED LOSS (GAIN) Crude oil and NGLs financial instruments $ 501 $ 95 $ 114 Natural gas financial instruments 5 88 3 Interest rate swaps (32) (35) (34) ----------- --------- -------- $ 474 $ 148 $ 83 ----------- --------- -------- UNREALIZED LOSS (GAIN) Crude oil and NGLs financial instruments $ (47) $ - $ - Natural gas financial instruments - - - Interest rate swaps 7 - - ----------- --------- -------- $ (40) $ - $ - ----------- --------- -------- TOTAL $ 434 $ 148 $ 83 =========== ======== =======
The effect of the realized loss from crude oil and NGLs and natural gas financial instruments was to reduce the Company's average realized prices as follows:
2004 2003 2002 ------------------------------------------------------------------------------------------------------------------------------ Crude oil and NGLs($/bbl) $ 4.85 $ 1.07 $ 1.46 Natural gas ($/mcf) $ 0.01 $ 0.19 $ 0.01 =========== ========= ========
The effect of the realized gain on interest rate swaps on the Company's interest expense was:
($ millions, except interest rates) 2004 2003(1) 2002(1) ------------------------------------------------------------------------------------------------------------------------------ Interest expense as per the financial statements $ 189 $ 201 $ 203 Less: realized risk management gain (32) (35) (34) ------------ --------- -------- $ 157 $ 166 $ 169 =========== ========= ======== Average effective interest rate 4.4% 4.8% 4.8% =========== ========= ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). 50 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS FOREIGN EXCHANGE
($ millions) 2004 2003(1) 2002(1) ------------------------------------------------------------------------------------------------------------------------------ Realized foreign exchange loss $ 3 $ 8 $ 4 Unrealized foreign exchange gain (94) (343) (36) Total $ (91) $ (335) $ (32) =========== ======= ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). The majority of the unrealized foreign exchange gain is related to the fluctuation of the Canadian dollar in relation to the US dollar. The Canadian dollar ended the year 2004 at US$0.8308 compared to US$0.7738 at December 31, 2003 (December 31, 2002 - US$0.6331). The majority of the Company's borrowings are denominated in US dollars. At December 31, 2004, the Company's US dollar denominated debt amounted to US$2,969 million compared to US$2,045 million in 2003 (2002 - US$2,048 million). US dollar denominated debt represented 77% of total debt outstanding at December 31, 2004 (2003 - 85%, 2002 - 77%). Due to the higher proportion of US dollar denominated debt outstanding, the Company's net earnings are more sensitive to fluctuations in the Canadian dollar. In order to mitigate a portion of the volatility associated with the Canadian dollar, the Company has designated certain US dollar denominated debt as a hedge against its net investment in US dollar based self-sustaining foreign operations. Accordingly, translation gains and losses on this US dollar denominated debt are included in the foreign currency translation adjustment in shareholders' equity in the consolidated balance sheets. The Company's realized product prices are sensitive to currency exchange rates. Recent increases in the value of the Canadian dollar in relation to the US dollar had a negative impact on the Company's commodity prices realized (see Sensitivity Analysis). TAXES
($ millions, except income tax rates) 2004 2003 2002 ------------------------------------------------------------------------------ TAXES OTHER THAN INCOME TAX Current $ 210 $ 116 $ 53 Deferred (45) $ (9) $ 10 Total $ 165 $ 107 $ 63 CURRENT INCOME TAX North America - Current income tax $ 89 $ 43 $ - North America - Large Corporations Tax $ 11 $ 16 $ 21 North Sea $ 2 $ 23 $ (19) Offshore West Africa $ 13 $ 10 $ 6 Other $ 1 $ - $ - Total $ 116 $ 92 $ 8 FUTURE INCOME TAX (1) $ 474 $ 338 $ 375 EFFECTIVE INCOME TAX RATE (1) 29.6% 23.5% 41.6% ==== ==== ====
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). Taxes other than income tax consist of current and deferred petroleum revenue tax ("PRT"), other international taxes and provincial capital taxes and surcharges. PRT is charged on certain fields in the North Sea at the rate of 50% of net operating income after certain deductions including abandonment expenditures. Taxes other than income tax increased to $165 million or $0.88 per boe in 2004, up from $107 million or $0.64 per boe in 2003 (2002 - $63 million or $0.41 per boe). The increase in taxes other than income tax was mainly due to the higher netback earned in the North Sea as a result of higher crude oil prices and higher production levels. North Sea PRT accounts for $145 million or $0.77 per boe in 2004 compared to $97 million or $0.58 per boe in 2003 (2002 - $51 million or $0.33 per boe). Taxable income from the conventional crude oil and natural gas business in Canada is generated by partnerships and the related income taxes will be payable in the following year. Current income taxes have been provided on the basis of the corporate structure and available income tax deductions and will vary depending upon the amount of capital expenditures incurred in Canada and the way it is deployed. No current income tax provision was required for North America in 2002. The Company is liable for the payment of Federal Large Corporations Tax ("LCT"). LCT decreased to $11 million or $0.09 per boe from $16 million or $0.14 per boe (2002 - $21 million or $0.11 per boe) as a result of the Company being taxable and a partial offset available in the calculation of the Federal corporate surtax. In addition, the LCT rate was reduced from 0.225% to 0.2% in 2004 as part of the phased elimination of LCT over five years. 51 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT It is anticipated that, based on the current availability of approximately $4.5 billion of tax pools in Canada at the end of 2004 and current commodity strip prices, the Company will be cash taxable in Canada in 2005 in the amount of $200 million to $300 million. Current income tax in the North Sea decreased to $2 million or $0.01 per boe, down from $23 million or $0.14 per boe in 2003 (2002 - recovery of $19 million or $0.13 per boe). The decrease in the current income tax expense was due to tax pools acquired in the recent acquisition being immediately deductible. The North Sea current income tax was also impacted by changes in the tax rules in the North Sea. In 2002, a supplementary charge of 10% on profits from UK North Sea crude oil and natural gas production was introduced. The North Sea supplementary charge, which took effect April 17, 2002, is in addition to the corporate income tax rate of 30% and excludes any deduction for financing costs. In addition, the first year capital allowance rate for plant and machinery expenditures was increased to 100% from the previous rate of 25%. The Company's future income tax provision for 2004 increased to $474 million ($2.53 per boe), up from $338 million ($2.02 per boe) in 2003 (2002 - $375 million or $2.45 per boe). In 2004 the North America future income tax liability was reduced by $66 million as a result of a reduction in the Alberta corporate income tax rate (2003 - $31 million, 2002 - $21 million). In 2003, the Federal Government introduced legislation to reduce the corporate income tax rate on income from resource activities over a five-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 elimination of the existing 25% resource allowance and the introduction of a deduction for actual provincial and other crown royalties paid. As a result of the Federal tax rate reductions, the future income tax liability in North America was decreased by $247 million in 2003. In 2002, the future income tax liability in the North Sea was increased by $34 million as a result of the introduction of a 10% supplementary charge on profits from North Sea crude oil and natural gas production. The following table shows the effect of non-recurring benefits on income taxes:
($ millions, except income tax rates) 2004 2003 2002 ------------------------------------------------------------------------------------------------------------------------------- Income tax as reported Current income tax $ 116 $ 92 $ 8 Future income tax expense(1) $ 474 $ 338 $ 375 ----------- -------- -------- $ 590 $ 430 $ 383 Alberta corporate tax rate reduction $ 66 $ 31 $ 21 Federal corporate tax rate reduction $ - $ 247 $ - UK supplementary tax on profits $ - $ - $ (34) ----------- -------- -------- Total $ 656 $ 708 $ 370 =========== ======== ======== Expected effective income tax rate 32.9% 38.6% 40.2% =========== ======== ========
(1) Restated for changes in accounting policies (see consolidated financial statements note 2). CAPITAL EXPENDITURES
($ millions) 2004 2003 2002 -------------------------------------------------------------------------------- EXPENDITURES ON PROPERTY, PLANT AND EQUIPMENT Net property acquisitions(1) $1,835 336 2,833 Land acquisition and retention 120 154 114 Seismic evaluations 89 77 63 Well drilling, completion and equipping 1,394 1,194 626 Pipeline and production facilities 821 522 292 ------ ----- ----- TOTAL NET RESERVE REPLACEMENT EXPENDITURES 4,259 2,283 3,928 Horizon Oil Sands Project 291 152 68 Midstream 16 11 20 Abandonments 32 40 43 Head office 35 20 10 ------ ----- ----- TOTAL NET CAPITAL EXPENDITURES $4,633 2,506 4,069 ====== ===== ===== BY SEGMENT North America $3,355 1,769 3,420 North Sea 608 338 323 Offshore West Africa 296 176 185 Horizon Project 291 152 68 Midstream 16 11 20 Abandonments 32 40 43 Head office 35 20 10 ------ ----- ----- TOTAL $4,633 2,506 4,069 ====== ===== =====
(1) Includes Business Combinations. 52 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The Company's strategy is focused on building a diversified asset base that is balanced between various products. The capital expenditures program continues to reflect this strategy. In 2004, capital expenditures were $4,633 million, including the acquisition of Petrovera, compared to $2,506 million in 2003 (2002 - $4,069 million including the acquisition of Rio Alto). The increase in capital expenditures was a result of property acquisitions made in the North America and North Sea segments. The Company continues to make significant progress on its larger, future-growth projects while maintaining its focus on existing assets. The Company's drilling activity decreased 19% with the drilling of 1,449 net wells compared to 1,793 net wells drilled in 2003 (2002 - 900 net wells). The Company drilled 689 net natural gas wells, down 11 % from the 777 net wells in 2003 (2002 - 162 net wells) and 328 net crude oil wells, down 28% from the 458 net wells in 2003 (2002 - 264 net wells). In addition, during 2004 the Company drilled 336 net stratigraphic test/service wells primarily on the oil sands leases in the Horizon Project and in the Northern Plains core region, down 24% from the 440 net wells in 2003 (2002 - 447 net wells), and 96 net wells that were dry and abandoned, down 19% from the 118 net wells in 2003 (2002 - 27 net wells). The total number of wells drilled decreased from the prior year due to the reallocation of capital resulting from the strategic acquisitions completed in 2004. The Company achieved an overall success rate of 91%, excluding stratigraphic test and service wells. These excellent results reflect the disciplined approach that the Company takes in its exploitation and development programs and the strength of its asset base. NORTH AMERICA North America accounted for 80% of the total capital expenditures in 2004 compared to 79% in 2003 (2002 - 86%). In 2004, the Company drilled 689 net natural gas wells, including 163 net wells in the Northern Plains core region, 221 net wells in the Southern Plains core region targeting shallow gas, 138 net wells in Northwest Alberta and 167 net wells in Northeast British Columbia. The Company also drilled 317 net crude oil wells in 2004. These wells were concentrated in the Company's Northern Plains crude oil region where 238 net heavy crude oil wells were drilled. Included in this figure were 58 net high-pressure horizontal thermal crude oil wells that were drilled and completed at Primrose as part of the 2004 development strategy of the area. As part of the development of the Company's heavy crude oil resources, the Company is continuing with its Primrose thermal project, which includes the Primrose North expansion project and drilling additional wells in the Primrose South project to augment existing production. At Primrose South, production was commissioned from the two new phases that commenced construction in 2003. The Primrose North expansion continues to be on track and on budget with total capital expenditures of approximately $300 million expected to be incurred, leading to first oil of 30 mbbl/d in 2006. Late in the third quarter, the Company filed a public disclosure document for regulatory approval of its Primrose East project, a new facility located about 15 kilometres from its existing Primrose South steam plant and 25 kilometres from its Wolf Lake central processing facility. Once completed, Primrose East will be fully integrated with existing operations at Wolf Lake, Primrose South and Primrose North. The Company currently expects to complete its regulatory application by late 2005 with a regulatory decision expected in late 2006. The Pelican Lake enhanced crude oil recovery project continues on track. The waterflood has provided initial production increases as expected and has shown positive waterflood response. The waterflood project will be expanded in 2005 and the Company plans to enhance the process by use of a polymer flood. The polymer flood pilot will commence during 2005 with three injectors and five producers. In February 2004, the Company acquired certain resource properties in its Northern Plains core region, collectively known as Petrovera, for $471 million. Strategically, the acquisition fit with the Company's objective of dominating its core regions and related infrastructure. The Company achieved cost reductions through synergies with its existing facilities, including additional throughput in its 100% owned ECHO Pipeline. The acquisition is included in the results of operations commencing February 2004. In the second quarter of 2004, the Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest Alberta for $280 million. These properties include a further ownership interest in the Ladyfern natural gas field. In addition, the Company acquired undeveloped pools with significant natural gas potential in deeper zones and will add a new exploration base in the Alberta Foothills. In the fourth quarter of 2004, the Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan for $703 million. The acquisition also includes over 510,000 net acres of unproven land. The acquisition has been included in operations effective December 2004. The acquisition fits the Company's strategy of dominating its core regions and related infrastructure, as the vast majority of the properties acquired are located within its core regions. The acquisition extends the Company's Northern Plains core region into the light crude oil operating area of Dawson. During the fourth quarter, the Company increased capital spending levels directed toward natural gas drilling in an effort to reduce pressures of a tight 2005 winter drilling season by starting earlier. This effort included a detailed and sequential drilling program that facilitated the procurement of better drilling rigs and crews for the winter season, both of which are an integral part of cost control. Certain portions of the drilling program were delayed due to warmer than expected weather through mid-December; however, the Company still expects to complete the majority of its plan. 53 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Midstream The Cold Lake Pipeline Limited Partnership, in which the Company has a 15% working interest, completed the construction of new facilities to allow shipment of up to 60,000 bbl/d of DilSynBit product. The new DilSynBit product will include light synthetic oil as a blending component to dilute the heavy, tar-like Cold Lake bitumen. The DilSynBit project will involve construction of two 80,000 barrel storage tanks, pumping facilities and metering equipment on the Cold Lake system. Horizon The third phase of the front-end engineering for the Horizon Project, Engineering Design Specification ("EDS"), was completed and ongoing detail work continues. The EDS provided sufficient definition for a lump sum inquiry for the detailed Engineering, Procurement and Construction ("EPC") of the various project components. The EDS also provided a detailed cost estimate and the basis upon which management made the final recommendation to the Board of Directors for sanction of the Horizon Project. The Company received regulatory approvals from the Alberta Energy and Utilities Board as well as the Alberta Provincial Cabinet and the Federal Cabinet in the first quarter of 2004. In the fourth quarter, site preparation work continued as well as work on the construction of onsite access roads, camps and the installation of deep underground facilities such as electrical, natural gas, water and sewage. In addition, clarification of bid documents occurred, resulting in the Company being able to obtain approximately 68% of Phase 1 costs on a fixed cost basis. The current estimate for Phase 1 construction costs now totals approximately $6.8 billion, including a contingency reserve of $700 million. The total cost for all three phases of the Horizon Project is now expected to be approximately $10.8 billion. On February, 9, 2005, the Board of Directors unanimously authorized management to proceed with Phase 1 of the Horizon Project. North Sea The Company continued with its planned program of infill drilling, recompletions, workovers and waterflood optimizations. During 2004, the Company commenced development drilling of the Lyell Field and the infill drilling program at the Ninian Field continued. In addition, one production and one injection well were completed at the Columba B terrace, and the Playfair well was completed in the fourth quarter with a production rate of 5 mbbl/d and sufficient associated natural gas to provide the Murchison Platform energy needs, thereby reducing production costs. During the third quarter of 2004, the Company acquired certain light crude oil producing properties in the Central North Sea. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields), together with associated production facilities, including a fixed platform Floating Production Vessel ("FPV") and adjacent exploration acreage. The Company equity interests in the producing fields acquired are: T-Block Tiffany, Toni and Thelma 100.00% B-Block Balmoral 70.20% Glamis 75.29% Stirling 68.68% The Company continued with the implementation of the natural gas reinjection project at the Banff Field in the Central North Sea, with reinjection commencing in November 2004. The project is expected to increase the overall reservoir recovery of crude oil, but will result in reductions in natural gas volumes. Offshore West Africa Offshore West Africa capital expenditures include the development of the Baobab Field where drilling is ongoing. To date, production testing on four producer wells has met or exceeded expectations. In addition, the Floating Production, Storage and Offtake Vessel ("FPSO") has been completed and is now moored on location. During the fourth quarter of 2004, the Acajou North exploration well was drilled to delineate the extent of the previously drilled Acajou discovery. The result of this well did not yield sufficient hydrocarbons to merit a stand alone development at Acajou. However, this field is being evaluated for future tie-back to East Espoir. At Zaizou, an exploration well spudded late in the fourth quarter was unsuccessful and the data obtained from this well is currently being used to trace the pattern of oil migration in the area to help identify future exploration targets. The planned development of the nearby West Espoir Field was sanctioned by partners with various components out for bid. The development is progressing on schedule and is expected to commence production in mid 2006 through existing FPSO facilities. Finally, additional review of seismic and geological data on Block 16 located offshore Angola indicates that while significant upside remains a possibility, its risk level is outside the normal operating parameters of the Company. As a result, the Company continues to evaluate alternatives for its holdings in the Block. 54 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS Liquidity and capital resources
($ millions, except ratios) 2004 2003(1) 2002(1) --------------------------- -------- -------- -------- Working capital deficit (2) $ 652 $ 505 $ 14 Long-term debt $ 3,538 $ 2,748 $ 4,200 ------- ------- ------- Shareholders' equity Share capital $ 2,408 $ 2,353 $ 2,304 Retained earnings 4,922 3,650 2,424 Foreign currency translation adjustment (6) 3 26 ------- ------- ------- Total $ 7,324 $ 6,006 $ 4,754 ======= ======= ======= Debt to cash flow (2)(3) 1.0x 0.9x 1.9x Debt to EBITDA (2)(3) 0.9x 0.8x 1.7x Debt to book capitalization (2) 33.8% 32.8% 47.1% Debt to market capitalization (2) 21.4% 25.1% 40.3% After tax return on average common shareholders' equity (3) 21.4% 25.6% 13.0% After tax return on average capital employed (2)(3) 15.3% 17.1% 8.8%
------------ (1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Includes current portion of long-term debt. (3) Based on trailing 12-month activity. At December 31, 2004, the working capital deficit amounted to $652 million and includes the current portion of other long-term liabilities of $260 million, consisting of stock based compensation of $243 million and the mark to market valuation of certain Risk Management financial derivative instruments of $17 million. The settlement of the stock-based compensation liability is dependant upon 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 settlement of the Risk Management financial derivative instruments is primarily dependant upon the underlying crude oil and natural gas prices at the time of settlement of the financial derivative instrument, as compared to the value at December 31, 2004. The Company is committed to maintaining its strong financial position throughout construction of the Horizon Project. In 2004, strong operational results and strong commodity prices enabled the Company to maintain debt levels at 33.8% of book capitalization. The Company has built the necessary financial capacity to complete the Horizon Project while at the same time not compromising delivery of low-risk conventional oil and natural gas growth opportunities. The financing of the first phase of the Horizon Project development will be 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, 2004, such as Baobab, Primrose and West Espoir provide identified growth in production volumes in 2005 and 2006, and will generate incremental free cash flows during the period 2005 to 2008 with which to finance the Horizon Project. In January 2005, the Board of Directors of the Company authorized an expanded hedging program for the Company in an effort to reduce the risk of volatility in commodity price markets and to underpin the Company's cash flow through the Horizon Project construction period. This expanded program allows for up to 75% of the near 12 months estimated 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 to be hedged. This revised hedging program allows the Company to have greater stability in its free cash flow and enhances the Company's financial flexibility during the Horizon Project construction years. The Company currently has collar hedges covering approximately 71% and 45% of estimated 2005 and 2006 crude oil production respectively. Similarly, approximately 67% and 35% of estimated 2005 and 2006 natural gas production has been hedged. The Company may also look to offload capital commitments through the acceptance of complementary business partners, or potentially, project joint venture partners. 55 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Long-term debt Long-term debt at December 31, 2004, increased $790 million from the prior year. The debt to EBITDA ratio increased to 0.9x and the debt to book capitalization increased to 33.8% compared to a debt to EBITDA ratio of 0.8x and a debt to book capitalization of 32.8% in 2003. 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 40% to 45%. At December 31, 2004, the Company had: o $2.8 billion of available unused bank credit facilities; o A fixed / floating interest rate mix of 43% / 57%; o 77% of borrowings denominated in US dollars; and o 85% of total long-term debt as non-bank based borrowing with a weighted average maturity of 16 years. 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 fixed rate interest coupon into a floating interest rate on the securities due December 2014. The Company filed a short form prospectus in May 2003 that allows for the issue of up to US$2 billion of debt securities in the United States until June 2005. Currently the Company has US$1.3 billion remaining under the $2 billion shelf prospectus. If issued, these securities will bear interest as determined at the date of issuance. In addition, the Company maintains a shelf prospectus in Canada for the offering of up to $1 billion of medium-term notes in Canada. If issued, these securities will bear interest as determined at the date of issuance. Future offerings under the shelf prospectuses will provide flexibility to the Company's debt investment base, extend maturities and provide balance in the fixed to floating interest rate mix. As at December 31, 2004, the Company had unsecured bank credit facilities of $3,425 million compared to $1,925 million at the close of 2003 (2002 - $2,275 million). In December 2004, the Company executed a $1,500 million, 5-year revolving credit facility, with three, one-year extension options. The ratings of the Company's debt securities and its relationships with principal banks are extremely important to the Company as it continues to expand and grow. Hence, the Company's management will continually undertake to maintain a strong balance sheet and financial position. The Company's debt securities are rated "Baa1" by Moody's Investor Services Inc., "BBB+" by Standard & Poors Corporation and "BBB(high)" by Dominion Bond Rating Services Limited. 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 6, 2004. The Company is authorized to issue an unlimited number of common shares. As at December 31, 2004, there were 268,181,000 common shares outstanding. As at February 18, 2005 there were 268,221,000 common shares outstanding. In addition, the Company is authorized to issue 200,000 Class 1 preferred shares. There were no preferred shares outstanding during these periods. During 2004, the Company issued 1,591,000 common shares from the exercise of stock options for proceeds of $24 million. During 2003, the Company issued 5,381,000 common shares from the exercise of stock options for proceeds of $89 million. In 2002, the Company issued 20 million common shares at an attributed value of $522 million as part of the consideration to acquire Rio Alto. A further 5,046,000 common shares were issued from the exercise of stock options throughout 2002 for proceeds of $82 million. In January 2005, the Company renewed its Normal Course Issuer Bid allowing it to purchase up to 13,409,006 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, 2004, the Company had purchased 873,400 common shares for a total cost of $33 million at an average purchase price of $38.01 per common share pursuant to a Normal Course Issuer Bid that has been in place since January 24, 2004. 56 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The Company declared dividends on common shares in the amount of $107 million or $0.40 per common share in 2004, up from $81 million or $0.30 per common share in 2003 (2002 - $64 million, $0.25 per common share). In February 2005, the Company's Board of Directors approved an increase in the annual dividend paid by the Company to $0.45 per common share for 2005. The 12.5% increase recognizes the stability of the Company's cash flow and provides a return to Shareholders. This is the fifth consecutive year in which the Company has paid dividends and the fourth consecutive year of an increase in the distribution paid to its Shareholders. In February 2004, the Company's Board of Directors approved an increase in the annual dividend paid by the Company to $0.40 per common share in 2004, up from the previous level of $0.30 per common share. Commitments and off balance sheet arrangements In the normal course of business, the Company has entered into various contractual arrangements and commitments that will have an impact on the Company's future operations. These contractual obligations and commitments relate primarily to debt repayments, operating leases relating to office space and offshore production and storage vessels, firm commitments for gathering, processing and transmission services. The following table summarizes the Company's commitments as at December 31, 2004:
($ millions) 2005 2006 2007 2008 2009 Thereafter ------------ ------ ------ ------ ------ ------ ---------- Natural gas transportation $ 194 $ 147 $ 100 $ 78 $ 37 $ 168 Crude oil transportation and pipeline $ 11 $ 9 $ 11 $ 12 $ 13 $ 154 Offshore equipment operating lease $ 110 $ 48 $ 48 $ 48 $ 48 $ 184 Baobab Project $ 99 $ - $ - $ - $ - $ - Offshore drilling and other $ 125 $ 8 $ - $ - $ - $ - Electricity $ 26 $ 28 $ 20 $ 13 $ 8 $ 34 Office lease $ 21 $ 21 $ 22 $ 23 $ 24 $ 30 Processing $ 5 $ 2 $ - $ - $ - $ - Horizon Project $ 99 $ - $ - $ - $ - $ - Long-term debt $ 194 $ - $ 162 $ 37 $ 69 $2,713
Subsequent event On February 9, 2005, the Company's Board of Directors unanimously authorized the Company to proceed with Phase 1 of the Horizon Oil Sands 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 targeted to begin at 110,000 bbl/d of 34 degree API light sweet, synthetic crude oil ("SCO"). Phase 2 would increase production to 155,000 bbl/d of SCO. Phase 3 would further increase production to 232,000 bbl/d of SCO. Total expected capital costs for all three phases of development are estimated at $10.8 billion. Capital costs for the first phase of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million, with $1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion to be incurred in 2006, 2007 and 2008, respectively. Oil and natural gas reserves Canadian Natural retains qualified independent reserve evaluators, Sproule Associates Limited ("Sproule"), and Ryder Scott Company ("Ryder Scott"), to evaluate 100% of the Company's proved and probable oil and natural gas reserves and prepare Evaluation Reports on the Company's total reserves. Sproule evaluated the North American assets and Ryder Scott evaluated the international assets and a portion of the North American assets. Canadian Natural has been granted an exemption from the 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. The primary difference between the two standards is the additional requirement under NI 51-101 to disclose proved and probable reserves and future net revenues using forecast prices and costs. Canadian Natural has elected to disclose proved reserves using constant prices and costs as mandated by the SEC and has also provided proved and probable reserves under the same parameters as voluntary additional information. Another difference between the two standards is in the definition of proved reserves; however, as discussed in the Canadian Oil and Gas Evaluation Handbook ("COGEH"), the standards which NI 51-101 employs, the difference in estimated proved reserves based on constant pricing and costs between the two standards is not material. Canadian Natural has significant oil reserves that are considered heavy with a gravity of less than 20 degrees. Heavy crude oil sells at a discount to light crude oil using the benchmark West Texas Intermediate, which has an API gravity of approximately 40 degrees, because it requires upgrading before it can be processed by conventional refineries. There is a finite capacity for upgrading in North America, which is often reached when heavy crude oil from other countries enters the North American market. Heavy crude oil requires blending with condensate or light synthetic crude oil ("diluent") in order for it to be transported in a pipeline. During the winter, heavy crude oil requires a higher proportion of diluent because of the cold temperatures. Heavy crude oil is also processed into asphalt, which is typically in demand during the spring to fall paving months. As a result of these factors, prices for heavy crude oil are historically low in December. Exacerbating this trend was reduced demand for heavy crude oil due to refinery turnarounds and other operational issues. During 2004 the price of heavy crude oil averaged US$30.40 per barrel but on December 31, 2004, the date the Company's oil and natural gas reserves were evaluated, the calculated price of Hardisty 12 degree API heavy crude oil was less. As a result, 30 mmbbl of net proved heavy crude oil reserves did not produce positive cash flow and, in accordance with SEC regulations, were debooked. Notwithstanding the economics at December 31, 2004, the current price of heavy crude oil has returned to a price sufficient to return the reserves subtracted by negative revision to the proved reserve category. 57 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Horizon oil sands mining reserves are not part of Canadian Natural's year-end reserves disclosure. Horizon reserves were evaluated as at February 9, 2005. Gilbert Laustsen Jung Associates Ltd. ("GLJ"), an independent qualified reserves evaluator, was retained by the Reserves Committee of Canadian Natural's Board of Directors to evaluate reserves associated with the Horizon Project incorporating both the mining and upgrading projects. These reserves were evaluated under SEC Industry Guide 7. The Board of Directors of the Company has a Reserves Committee, which has met with and carried out independent due diligence procedures with each of Sproule, Ryder Scott and GLJ as to the Company's reserves. Additional reserve disclosure is contained in the supplementary oil and gas information and the Company's Annual Information Form. Risks and uncertainties The Company is exposed to several operational risks inherent in exploring, developing, producing and marketing crude oil and natural gas. These inherent risks include: economic risk of finding and producing reserves at a reasonable cost; financial risk of marketing reserves at an acceptable price given current market conditions; cost of capital risk associated with securing the needed capital to carry out the Company's operations; risk of fluctuating foreign exchange rates; risk of carrying out operations with minimal environmental impact; risk of governmental policies, social instability or other political, economic or diplomatic developments in its international operations; and credit risk of non-payment for sales contracts or non-performance by counterparties to contracts. 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. 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 current position with respect to its financial instruments is detailed in note 12 to the consolidated financial statements. The arrangements and policies concerning the Company's financial instruments are under constant review and may change depending upon the prevailing market conditions. The Company's capital structure mix is also monitored on a continual basis to ensure that it optimizes flexibility, minimizes cost and offers the greatest opportunity for growth. This includes the determination of a reasonable level of debt and any interest rate exposure risk that may exist. 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. Environment The Company's environmental management plan and operating guidelines focus on minimizing the impact of field operations while meeting regulatory requirements and corporate standards. The Company, as part of this plan, has implemented a proactive program that includes: o An annual internal environmental compliance audit and inspection program of the Company's operating facilities; o An aggressive suspended well inspection program to support future development or eventual abandonment; o Appropriate reclamation and decommissioning standards for wells and facilities ready for abandonment; o An effective surface reclamation program; o A progressive due diligence program related to groundwater monitoring; o A rigorous program related to preventing and reclaiming spill sites; o A solution gas reduction and conservation program; and o 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: o Using water-based, environmentally friendly drilling muds whenever possible; o Implementing cost effective ways of reducing greenhouse natural gas emissions per unit of production; 58 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS o Exercising care with respect to all waste produced through effective waste management plans; and o Minimizing produced water volumes onshore and offshore through cost-effective measures. In 2004, the Company's capital expenditures included $32 million for abandonment expenditures, down from $40 million in 2003 (2002 - $43 million). Estimated future site restoration liability
($ millions) 2004 2003 ------------ ------- ------- North America $ 1,776 $ 1,491 North Sea 1,263 764 Offshore West Africa 24 26 ------- ------- 3,063 2,281 North Sea PRT recovery (601) (331) ------- ------- $ 2,462 $ 1,950 ======= =======
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 specific environmental legislation. The estimated costs are based on engineering estimates using current costs and technology in accordance with present legislation and industry practice. It is important to note that the future abandonment costs to be incurred by the Company in the North Sea will result in an estimated recovery of PRT of $601 million (2003 - $331 million, 2002 - $305 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 $2,462 million (2003 - $1,950 million, 2002 - $1,681 million). 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 ratified the Kyoto Protocol ("Kyoto"). The Company continues to work with departments of the Federal and Provincial governments as legislation and regulatory mechanisms to address the issue of climate change develop. The Federal Government has addressed the uncertainty around the ratification and implementation of Kyoto by providing the oil and gas sector with limits on the cost for large industrial emitters until 2012. For long-term, capital intensive investments, such as the Horizon Project, it is essential for the Company to understand the cost implications associated with the climate change policies beyond 2012. To address these concerns, the Federal Government outlined eight principles that would guide them in its negotiations and policies for the post 2012 years. On the basis of these principles, the Company continued to work on the development plan of the Horizon Project. Accordingly, 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. Critical accounting estimates The preparation of financial statements requires Management to make judgements, assumptions and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. Actual results could differ from those estimates. A comprehensive discussion of the Company's significant accounting policies is contained in note 1 to the consolidated financial statements. The following is a discussion of the accounting estimates that are critical in determining the Company's financial results. Full cost accounting The Company follows the full cost method of accounting for oil and natural gas properties and equipment as prescribed by the CICA. Accordingly, all costs relating to the exploration for and development of oil and natural gas reserves are capitalized and accumulated in country-by-country cost centres. 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. The carrying amount of 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, then an impairment loss equal to the amount by which the carrying amount of the properties exceeds their fair value is charged against net earnings. 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. 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. The alternate acceptable method of accounting for 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. 59 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Oil and natural gas reserves The Company retains qualified independent reserves evaluators to evaluate the Company's proved and probable oil and natural gas reserves. In 2004, 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. A revision to the reserve estimate could 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 oil and natural gas property, plant and equipment carrying amounts under the ceiling test. Asset retirement obligation The fair value 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 fair value of the asset retirement obligations are capitalized as part of the cost of associated capital assets and are 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 credit-adjusted risk-free interest rate. 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. 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 settlement of the asset retirement obligations. Risk management activities Financial instruments that do not qualify as hedges under Accounting Guideline 13 or are not designated as hedges are recorded at fair value on the Company's consolidated balance sheet, with subsequent changes in fair value recognized in net earnings. The Company utilizes various financial instruments to manage its commodity prices, foreign currency and interest rate exposures. These financial instruments are not used for trading purposes. 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. The Company also enters into foreign currency denominated financial instruments to manage future US dollar denominated crude oil and natural gas sales. 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 principle 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 interest rate contracts not designated as hedges are included in risk management activities. The Company enters into cross currency swap agreements to manage its currency exposure on 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 non-current 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 gain or loss is recognized in net earnings. Purchase price allocations The costs of corporate and asset acquisitions are allocated to the acquired assets and liabilities based on their fair value at the time of acquisition. The determination of fair value requires Management 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. Production sharing contractual arrangements The Company's operations outside of North America and the North Sea are governed by production sharing contracts ("PSC"). Under the PSC, the Company and its working interest partners typically bear all the risks and costs for exploration, development and production. In exchange, if exploration is successful, the Company is given the opportunity to recover its investment and production expenses from the sale of crude oil and natural gas production ("cost oil"). The Company is also entitled to a share of the excess of what is required to recover the Company's investment and production expenses ("profit oil"), the allocation of which varies from contract to contract. Together the cost oil and profit oil represent the Company's entitlement. The Company records production, sales and reserves based on its working interest ownership. The PSC stipulates that income taxes are to be paid out of the respective national oil company share of production. The difference between the Company's working interest ownership and its annual entitlement is accounted for either a royalty expense or current income tax expense in accordance with the PSC. 60 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS New accounting standards Full cost accounting Effective January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 16 "Oil and Gas Accounting - Full Cost". The Guideline modifies the ceiling test, which limits the aggregate capitalized costs that may be carried forward to future periods. Specific new guidance was provided on several issues, including the frequency of conducting cost centre impairment tests, the testing for cost centre recoverability and the method of determining fair value. The Guideline recommends that cost centre impairment tests should be conducted at each annual balance sheet date. Recovery of costs is tested by comparing the carrying amount of the oil and natural gas assets to their recoverable amount calculated as the undiscounted cash flows from those assets using proved reserves and expected future prices and costs. If the carrying amount exceeds the recoverable amount, then impairment should be recognized on the amount by which the carrying amount of the assets exceeds the fair value of the assets, calculated as the present value of expected cash flows using proved and probable reserves and expected future prices and costs. The adoption of this standard had no effect on the Company's consolidated financial statements for the year ended December 31, 2004. Asset retirement obligations Effective January 1, 2004, the Company retroactively adopted the CICA's Section 3110, "Asset Retirement Obligations". The Section requires the recognition of a liability for the fair value of the asset retirement obligation related to long-term assets. Retirement costs equal to the fair value of the asset retirement obligation are capitalized as part of the cost of the associated capital asset and amortized to expense through depletion over the life of the asset. 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. This new standard was adopted retroactively and prior period comparative balances have been restated. Adoption of the standard had the following effects on the Company's consolidated balance sheet as at December 31, 2003:
($ millions) December 31, 2003 ------------ ----------------- Consolidated balance sheet Increase property, plant and equipment $ 445 Decrease future site restoration liability $ (447) Increase asset retirement obligation $ 897 Increase future income tax liability $ 3 Decrease foreign currency translation adjustment $ (14) Increase retained earnings $ 6
Adoption of the standard had the following effects on the Company's consolidated statements of earnings and retained earnings:
Year Ended ($ millions) 2004 2003 2002 ------------ ------ ------ ------ Increase opening retained earnings $ 6 $ 10 $ 41 Decrease depletion, depreciation and amortization $ (120) $ (56) $ (16) Increase asset retirement obligation accretion $ 51 $ 62 $ 68 Increase (decrease) future income tax expense $ 28 $ (2) $ (21)
The Company's pipelines and co-generation plant have indeterminant lives and therefore the fair values of the related asset retirement obligations cannot be reasonably determined. The asset retirement obligation for these assets will be recorded in the year in which the lives of the assets are determinable. Risk management activities On January 1, 2004, the Company prospectively adopted the CICA's Accounting Guideline 13, "Hedging Relationships" and EIC 128, "Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments". Guideline 13 and EIC 128 require that financial instruments that are not designated as hedges be recorded on the Company's consolidated balance sheet at fair value on the date thereof, with subsequent changes in fair value recorded in earnings on a quarterly reporting basis. Adoption of Guideline 13 and EIC 128 resulted in the Company recognizing an unrealized mark-to-market gain of $40 million ($27 million, net of tax) for the year ended December 31, 2004 relating to its financial instruments. The unrealized gain assumes that all unsettled derivative financial instruments were settled on December 31, 2004 and were valued based on market conditions existing at that point in time. As a result of the adoption of this standard, the Company expects the volatility in its net earnings to increase, which is directly attributable to the corresponding volatility in crude oil and natural gas prices and the unsettled derivative financial instruments. The Guideline had the following effects on the Company's consolidated financial statements:
($ millions) January 1, 2004 ------------ --------------- Consolidated balance sheet Increase derivative financial instruments asset $ 40 Increase deferred revenue $ 40
61 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Preferred Securities Effective December 31, 2004, the Company early adopted changes to the CICA's Section 3860, "Financial Instruments - Presentation and Disclosure" that relate to contractual obligations that may be settled by delivery of the Company's common shares. Under the new rules, these obligations must be classified as liabilities on the Company's consolidated balance sheets. Previously, these obligations were classified as equity. These changes have been adopted retroactively and prior periods have been restated. Adoption of the changes had the following effects on the Company's consolidated financial statements:
($ millions) 2004 2003 2002 ------------ ------ ------ ------ Increase long-term debt $ 96 $ 103 $ 126 Decrease preferred securities $ (96) $ (103) $ (126) Increase interest expense $ 9 $ 9 $ 10 Increase foreign exchange gain $ 7 $ 23 $ 1 (Decrease) increase future income tax expense $ (1) $ 1 $ (4) Decrease dividend on preferred securities, net of tax $ (5) $ (5) $ (6) Decrease revaluation of preferred securities, net of tax $ (4) $ (18) $ (1)
Impairment of long-lived assets Effective January 1, 2004, the Company prospectively adopted the CICA's Section 3063 "Impairment of Long-lived Assets". The Section establishes standards for the recognition, measurement and disclosure of the impairment of long-lived assets. The Section addresses when impairment should be recognized and how to measure the amount of impairment. An impairment loss is recognized when the carrying amount of a long-lived asset exceeds its fair value calculated as the sum of the undiscounted cash flows expected to result from its use and eventual disposition. An impairment loss is measured as the amount by which the long-lived assets' carrying amount exceeds its fair value. Adoption of the Section had no effect on the Company's consolidated financial statements for the year ended December 31, 2004. Variable interest entities ("VIE's") Effective January 1, 2004, the Company retroactively adopted the CICA's Accounting Guideline 15, "Consolidation of Variable Interest Entities" without restating prior periods. The Guideline requires the Company to identify VIE's in which they have an interest, determine whether they are the primary beneficiary of such entities and, if so, consolidate them. The primary beneficiary is the enterprise that will absorb or receive the majority of the VIE's expected losses, expected residual returns, or both. A VIE is an entity where (1) its equity investment at risk is insufficient to permit the entity to finance its activities without additional subordinated support from others, (2) the equity investors lack either voting control, an obligation to absorb expected losses or the right to receive expected residual returns, and (3) it does not meet specified exemption criteria. The adoption of this Guideline had no impact on the Company's consolidated financial statements. Financial instruments In January 2005, the CICA issued Section 3855 "Financial Instruments - Recognition and Measurement". This Section prescribes when a financial asset, financial liability, or non-financial derivative is to be recognized on the balance sheet and at what amount - sometimes using fair value; other times using cost-based measures. This Section also specifies how financial instruments gains and losses are to be presented. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Transitional provisions for this Section are complex and vary based on the type of financial instruments under consideration. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Hedges In January 2005, the CICA issued Section 3865 "Hedges". This Section expands on existing Accounting Guideline 13, "Hedging Relationships", and Section 1650 "Foreign Currency Translation", by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Retroactive application of this Section is not permitted. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Comprehensive Income In January 2005, the CICA issued Section 1530 "Comprehensive Income". This Section introduces new standards for reporting and display of comprehensive income. Comprehensive income is the change in equity (net assets) of a 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. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain comprehensive income items. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. 62 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS Equity In January 2005, the CICA issued Section 3251 "Equity". This Section replaces Section 3250 "Surplus". It establishes standards for the presentation of equity and changes in equity during a reporting period. This Section applies to interim and annual financial statements relating to fiscal years beginning on or after October 31, 2006. Earlier adoption is permitted only as of the beginning of a fiscal year ending on or after December 31, 2004. The Company plans to adopt this Section on January 1, 2007. Financial statements of prior periods are required to be restated for certain specified adjustments. For all other items, comparative financial statements are presented are not restated, but an adjustment to the opening balance of accumulated other comprehensive income may be required. In addition, a company is encouraged, but not required to present reclassification adjustments, in comparative financial statements provided for earlier periods. The effect on the Company's consolidated financial statements cannot be reasonably determined at this time. Outlook The Company continues its strategy of maintaining a large portfolio of varied projects, which enables the Company 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 2005 to average 1,448 to 1,510 mmcf/d of natural gas and 307,000 to 335,000 bbl/d of crude oil and NGLs. First quarter 2005 production guidance for natural gas is 1,400 to 1,482 mmcf/d of natural gas and 269,000 to 290,000 bbl/d of crude oil and NGLs. The budgeted capital expenditures in 2005 are currently expected to be as follows:
($ millions) 2005 Budget ------------ ----------- North America natural gas $ 1,350 North America crude oil and NGLs 910 North Sea crude oil and NGLs 420 Offshore West Africa crude oil and NGLs 400 Property acquisitions and midstream 50 ------- 3,130 Horizon Oil Sands Project 1,372 ------- Total $ 4,502 =======
North America natural gas In 2005, the Company expects to drill approximately 1,033 net natural gas wells, 690 net crude oil wells and 199 stratigraphic test/service wells. The 2005 North American natural gas program will be highlighted by expanded drilling programs in the Northwest Alberta and Northeast British Columbia core regions as shown below:
(number of wells) 2005 Budget ----------------- ----------- Northeast British Columbia 240 Northwest Alberta 194 Northern Plains 205 Southern Plains 394 ----- Total 1,033 =====
Drilling in 2005 reflects higher activity levels targeting the shallow Notikewin zone in Northeast British Columbia as well as increased Cardium drilling in Northwest Alberta. Drilling of shallow gas and coal bed methane wells will increase in the Southern Plains core region. Conventional drilling will also increase in the Northern Plains core region. During 2005, approximately 90 wells targeting deep natural gas are budgeted, including nine in the Foothills area. The Foothills area drilling increases reflect both increased focus on the area as well as new drilling targets identified on assets acquired during the first half of 2004. 63 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT North America crude oil and NGLs The 2005 drilling program consists of:
(number of wells) 2005 Budget ----------------- ----------- Conventional heavy crude oil 398 Thermal heavy crude oil 105 Light crude oil 101 Pelican Lake crude oil 67 ----- Total 671 =====
The 2005 drilling program consists of 398 conventional heavy crude oil wells, 105 thermal heavy crude oil wells, 101 light crude oil wells and 67 Pelican Lake crude oil wells. The Company continues the disciplined development of its heavy crude oil resources. Conventional heavy crude oil drilling will increase, reflecting favourable crude oil prices as well as 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 2005. In 2005, the Company expects to continue its Primrose thermal crude oil expansion plans. The two new phases that commenced production in mid 2004 significantly enhance the economics of this project and are a positive indicator for future pads that will be drilled. 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 2004 production. The Pelican Lake waterflood test program continues and will be expanded to additional lands in the area. The Company will also be piloting the use of polymer flood on a portion of the field in an effort to further enhance field recoveries. As a result of the above activities, North America 2005 crude oil and NGLs production is expected to increase slightly from 2004 levels. Based upon the capital expenditure budget, the Company expects to incur Canadian current income tax expense in 2005 of $200 to $300 million. The Horizon Oil Sands 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 planned to begin at 110,000 bbl/d of 34 degree API light, sweet synthetic crude oil ("SCO"). Phase 2 will increase production to 155,000 bbl/d of SCO. Phase 3 will further increase production to 232,000 bbl/d of 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. Total expected capital costs for all three phases of the development are estimated at $10.8 billion. Capital costs for Phase 1 of the Horizon Project are estimated at $6.8 billion including a contingency reserve of $700 million with $1.4 billion to be incurred in 2005, and $2.2 billion, $2.0 billion and $1.2 billion to be incurred in 2006, 2007 and 2008, respectively. 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 will also reduce the risks associated with scope changes. On February, 9, 2005, the Board of Directors unanimously authorized management to proceed with Phase 1 of the Horizon Project. North Sea The capital budget in 2005 for the North Sea is $420 million and includes the drilling of approximately 12 net platform wells while continuing the successful workover and recompletion program. The Company will also conduct a mobile drilling program in which four subsea wells will be drilled at Nadia, Thelma (two) and Columba E. These wells, with the exception of Nadia, are step-out development wells on existing proved properties. The Nadia well is an exploration of new terraces in the Ninian/Columba area. Average crude oil production is expected to increase from 2004 production levels; however, natural gas volumes will be lower as natural gas sales at the Banff Field are diverted to reinjection. Offshore West Africa In 2005, the capital budget for Offshore West Africa is set at $400 million, of which the Company anticipates $210 million to be spent on finalizing the development of the Baobab Field in Cote d'Ivoire and $100 million to be spent developing the West Espoir Field. The remainder will be spent on various exploration activities. At East Espoir, an additional four wells are scheduled for drilling in early 2005 as a result of additional testing and evaluation that revealed a larger quantity of crude oil in place, based upon reservoir studies and production history to date. These new producer wells will effectively exploit this additional potential and could increase the recoverable resources from the field. Average production is expected to increase as a result of the commissioning of the Baobab Field in mid 2005 as well as a result of the drilling of additional producer wells in East Espoir. Sensitivity analysis The following table is indicative of the annualized sensitivities of cash flow and net earnings from changes in certain key variables. The analysis is based on business conditions and production volumes during the fourth quarter of 2004. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. 64 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS
Cash flow from Cash flow from operations operations Net earnings Net earnings ($ millions) ($/share, basic) ($ millions) ($/share, basic) ------------ ---------------- ------------ ---------------- Price changes Crude oil - WTI US$1.00/bbl (1) Excluding financial derivatives $ 96 $ 0.36 $ 68 $ 0.25 Including financial derivatives $ 80 $ 0.30 $ 43 $ 0.16 Natural gas - AECO C$0.10/mcf (1) Excluding financial derivatives $ 37 $ 0.14 $ 24 $ 0.09 Including financial derivatives $ 33 $ 0.12 $ 21 $ 0.08 Volume changes Crude oil - 10,000 bbl/d $ 73 $ 0.27 $ 34 $ 0.13 Natural gas - 10 mmcf/d $ 18 $ 0.07 $ 7 $ 0.03 Foreign currency rate change $0.01 change in C$ in relation to US$ (1) Excluding financial derivatives $ 56 $ 0.21 $ 12 $ 0.05 Including financial derivatives $ 55 - 58 $0.21 - 0.22 $ 12 - 13 $0.04 - 0.05 Interest rate change - 1% $ 13 $ 0.05 $ 13 $ 0.05
------------ (1) For details of financial instruments in place, see consolidated financial statements note 12. Daily production by segment, before royalties
Q1 Q2 Q3 Q4 2004 2003 2002 ------- ------- ------- ------- ------- ------- ------- Crude oil and NGLs (bbl/d) North America 192,151 203,741 214,336 214,493 206,225 174,895 169,675 North Sea 57,099 60,105 71,517 69,971 64,706 56,869 38,876 Offshore West Africa 12,036 11,552 11,409 11,240 11,558 10,628 6,784 ------- ------- ------- ------- ------- ------- ------- Total 261,286 275,398 297,262 295,704 282,489 242,392 215,335 ======= ======= ======= ======= ======= ======= ======= Natural gas (mmcf/d) North America 1,230 1,389 1,336 1,365 1,330 1,245 1,204 North Sea 54 55 53 40 50 46 27 Offshore West Africa 10 8 7 5 8 8 1 ------- ------- ------- ------- ------- ------- ------- Total 1,294 1,452 1,396 1,410 1,388 1,299 1,232 ======= ======= ======= ======= ======= ======= ======= Barrels of oil equivalent (boe/d) North America 397,194 435,238 436,986 442,072 427,936 382,315 370,337 North Sea 66,127 69,175 80,393 76,560 73,093 64,469 43,391 Offshore West Africa 13,623 12,930 12,567 12,113 12,806 12,030 6,994 ------- ------- ------- ------- ------- ------- ------- Total 476,944 517,343 529,946 530,745 513,835 458,814 420,722 ======= ======= ======= ======= ======= ======= =======
Per unit results
Q1 Q2 Q3 Q4 2004 2003 2002 ------- ------- ------- ------- ------- ------- ------- Crude oil and NGLs ($/bbl) Sales price (1) $ 34.21 $ 36.72 $ 43.50 $ 36.92 $ 37.99 $ 32.66 $ 31.22 Royalties 2.91 3.15 3.59 2.95 3.16 2.77 3.16 Production expense 9.58 9.92 10.21 10.41 10.05 10.28 8.45 ------- ------- ------- ------- ------- ------- ------- Netback $ 21.72 $ 23.65 $ 29.70 $ 23.56 $ 24.78 $ 19.61 $ 19.61 ======= ======= ======= ======= ======= ======= ======= Natural gas ($/mcf) Sales price (1) $ 6.31 $ 6.64 $ 6.24 $ 6.77 $ 6.50 $ 6.21 $ 3.77 Royalties 1.27 1.38 1.39 1.34 1.35 1.32 0.78 Production expense 0.65 0.66 0.71 0.68 0.67 0.60 0.57 ------- ------- ------- ------- ------- ------- ------- Netback $ 4.39 $ 4.60 $ 4.14 $ 4.75 $ 4.48 $ 4.29 $ 2.42 ======= ======= ======= ======= ======= ======= ======= Barrels of oil equivalent ($/boe) Sales price (1) $ 35.88 $ 38.20 $ 40.92 $ 38.51 $ 38.45 $ 34.84 $ 27.02 Royalties 5.03 5.55 5.68 5.21 5.37 5.20 3.91 Production expense 7.02 7.12 7.59 7.61 7.35 7.15 5.99 ------- ------- ------- ------- ------- ------- ------- Netback $ 23.83 $ 25.53 $ 27.65 $ 25.69 $ 25.73 $ 22.49 $ 17.12 ======= ======= ======= ======= ======= ======= =======
------------ (1) Including transportation costs and excluding risk management activities. 65 MANAGEMENT'S DISCUSSION AND ANALYSIS 2004 ANNUAL REPORT Netback analysis
($/boe, except daily production) 2004 2003 2002 -------- -------- -------- Daily production, before royalties (boe/d) 513,835 458,814 420,722 Sales price (1) $ 38.45 $ 34.84 $ 27.02 Royalties 5.37 5.20 3.91 Production expense 7.35 7.15 5.99 -------- -------- -------- Netback 25.73 22.49 17.12 Midstream contribution (0.26) (0.28) (0.25) Administration 0.61 0.52 0.40 Share bonus plan 0.05 - - Interest 1.01 1.20 1.26 Realized risk management activities loss 2.52 1.09 0.54 Realized foreign exchange loss 0.02 0.05 0.02 Taxes other than income tax - current 1.12 0.69 0.35 Current income tax - North America 0.47 0.14 - Current income tax - Large Corporations Tax 0.05 0.06 0.14 Current income tax - North Sea 0.01 0.26 (0.13) Current income tax - Offshore West Africa 0.07 0.09 0.04 Current income tax - other 0.01 - - -------- -------- -------- Cash flow $ 20.05 $ 18.67 $ 14.75 ======== ======== ========
------------ (1) Including transportation costs and excluding risk management activities. Quarterly financial information
($ millions, except per share amounts) Q1 Q2 Q3 Q4 Total ------- ------- ------- ------- ------- 2004 Revenue $ 1,638 $ 1,865 $ 2,075 $ 1,969 $ 7,547 Net earnings $ 258 $ 259 $ 311 $ 577 $ 1,405 Per common share - basic $ 0.96 $ 0.97 $ 1.16 $ 2.15 $ 5.24 - diluted $ 0.96 $ 0.97 $ 1.13 $ 2.13 $ 5.20 Cash flow from operations $ 848 $ 930 $ 1,041 $ 950 $ 3,769 Per common share - basic $ 3.16 $ 3.47 $ 3.88 $ 3.54 $ 14.06 - diluted $ 3.14 $ 3.47 $ 3.85 $ 3.52 $ 13.98 2003 $ 1,840 $ 1,502 $ 1,454 $ 1,359 $ 6,155 Net earnings (1) $ 427 $ 525 $ 201 $ 250 $ 1,403 Per common share - basic (1)(2) $ 1.60 $ 1.96 $ 0.75 $ 0.93 $ 5.23 - diluted (1)(2) $ 1.52 $ 1.89 $ 0.74 $ 0.91 $ 5.06 Cash flow from operations $ 906 $ 762 $ 758 $ 734 $ 3,160 Per common share - basic (2) $ 3.38 $ 2.84 $ 2.81 $ 2.74 $ 11.77 - diluted (2) $ 3.27 $ 2.79 $ 2.78 $ 2.71 $ 11.53
------------ (1) Restated for changes in accounting policies (see consolidated financial statements note 2). (2) Restated to reflect two-for-one share split in May 2004. 66 2004 ANNUAL REPORT MANAGEMENT'S DISCUSSION AND ANALYSIS The following discussion highlights some of the more significant factors that impacted the net earnings in the eight most recently completed quarters. In the first quarter of 2004, the Company acquired certain resource properties, collectively known as Petrovera, in its Northern Plains core region. In the second quarter of 2004, the Company completed the acquisition of certain resource properties located in Northeast British Columbia and Northwest Alberta. These properties include further ownership in the Ladyfern natural gas field. In the third quarter of 2004, the Company acquired certain light crude oil producing properties in the Central North Sea. The acquired properties comprise operated interests in T-Block (Tiffany, Toni and Thelma Fields) and B-Block (Balmoral, Stirling and Glamis Fields). In the fourth quarter of 2004, the Company completed the acquisition of certain resource properties located in Alberta, British Columbia and Saskatchewan. The acquisition extends the Company's Northern Plains core region into the light crude oil operating area of Dawson. The Company issued US$350 million of debt securities maturing 2014, bearing interest at 4.90% and US$350 million of debt securities maturing 2035, bearing interest at 5.85%. In the second quarter of 2003, the Canadian Government introduced several income tax changes, including rate reductions, for the resource industry. In addition, the Province of Alberta reduced corporate income tax rates. As a result of these changes, the future income tax liability was decreased by $247 million. Also, in the second quarter of 2003, the Company modified its employee stock option plan to provide for a cash payment option. A charge of $72 million after taxes ($105 million before taxes) was recognized to represent the mark-to-market liability of the plan for all earned options as at June 30, 2003. Trading and share statistics
2004 2003 Q1 Q2 Q3 Q4 Total Total --------- --------- --------- --------- -------- --------- TSX-C$ Trading volume (thousands) 69,449 80,934 65,017 87,612 303,012 295,351 Share price ($/share) High $ 38.25 $ 40.85 $ 51.04 $ 55.15 $ 55.15 $ 33.61 Low $ 31.91 $ 35.08 $ 39.75 $ 45.80 $ 31.91 $ 22.60 Close $ 36.35 $ 40.05 $ 50.50 $ 51.25 $ 51.25 $ 32.69 Market capitalization at December 31 ($ millions) $ 13,744 $ 8,742 Shares outstanding (thousands) 268,181 267,463 ----------------------------------------------------------------------------------------------------------------- NYSE - US$ Trading volume (thousands) 11,775 16,418 13,255 21,286 62,734 23,458 Share price ($/share) High $ 28.94 $ 30.54 $ 40.31 $ 44.74 $ 44.74 $ 25.70 Low $ 23.88 $ 25.88 $ 29.72 $ 37.12 $ 23.88 $ 14.63 Close $ 27.82 $ 29.90 $ 39.83 $ 42.77 $ 42.77 $ 25.22 Market capitalization at December 31 ($ millions) $ 11,470 $ 6,745 Shares outstanding (thousands) 268,181 267,463
67 CONSOLIDATED FINANCIAL STATEMENTS 2004 ANNUAL REPORT 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 which 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. /s/ John G. Langille /s/ Douglas A. Proll /s/ Randall S. Davis -------------------- ---------------------- ------------------------- JOHN G. LANGILLE CA DOUGLAS A. PROLL CA RANDALL S. DAVIS CA President & Director Senior Vice President, Vice President, Financial Finance Accounting & Controls February 18, 2005 Auditors' Report To the Shareholders of Canadian Natural Resources Limited, We have audited the consolidated balance sheets of Canadian Natural Resources Limited as at December 31, 2004 and 2003 and the consolidated statements of earnings, retained earnings and cash flows for each of the years in the three year period ended December 31, 2004. 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 consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated 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, 2004 and 2003 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles. /s/ PricewaterhouseCoopers LLP --------------------------------- Chartered Accountants Calgary, Alberta, Canada February 18, 2005 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 2 to the consolidated financial statements. Our report to the shareholders dated February 18, 2005 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. /s/ PricewaterhouseCoopers LLP --------------------------------- Chartered Accountants Calgary, Alberta, Canada February 18, 2005 68