Canadian Natural: Profit Down for Q4, Up for Full Year

For the year ended December 31, 2006, Canadian Natural Resources Limited reported record net earnings of $2,524 million compared to net earnings of $1,050 million for the year ended December 31, 2005.

Net earnings for the year ended December 31, 2006 included unrealized after-tax income of $860 million related to the effects of risk management activities, statutory tax rate changes on future income tax liabilities, fluctuations in foreign exchange rates and stock-based compensation expense, compared to $984 million of net after-tax expenses for the year ended December 31, 2005. Excluding these items, adjusted net earnings from operations for the year ended December 31, 2006 decreased to $1,664 million from $2,034 million for the year ended December 31, 2005, primarily due to decreased natural gas pricing, increased realized risk management losses on crude oil, increased production expense and depletion, depreciation and amortization expense and the impact of a stronger Canadian dollar relative to the US dollar. These factors were partially offset by stronger benchmark crude oil pricing and increased crude oil and NGLs and natural gas sales volumes.

Fourth quarter 2006 net earnings were $313 million compared to net earnings of $1,104 million in the fourth quarter of 2005 and net earnings of $1,116 million in the prior quarter. Net earnings in the fourth quarter of 2006 included unrealized after-tax expenses of $99 million related to the effects of risk management activities, fluctuations in foreign exchange rates and stock-based compensation expense, compared to net after-tax income of $503 million in the fourth quarter of 2005 and $646 million of after-tax income in the prior quarter. Excluding these items, adjusted net earnings from operations in the fourth quarter of 2006 decreased to $412 million from $601 million in the comparable period in 2005, and decreased from $470 million in the prior quarter. The decrease from the comparable period in 2005 was primarily due to decreased natural gas pricing, increased Company-wide production expense, increased depletion, depreciation and amortization expense and the impact of a stronger Canadian dollar relative to the US dollar. These factors were partially offset by the impact of increased crude oil pricing, increased crude oil and NGLs and natural gas sales volumes and decreased realized risk management losses on crude oil. The decrease from the prior quarter was primarily due to decreased crude oil and NGLs pricing and increased depletion, depreciation and amortization expense, partially offset by increased natural gas pricing, increased crude oil and NGLs and natural gas sales volumes and decreased realized risk management losses. Operating results in the fourth quarter of 2006 were impacted by the acquisition of Anadarko Canada Corporation ("ACC") completed in November 2006. The Company completed the acquisition of ACC, a subsidiary of Anadarko Petroleum Corporation, for net cash consideration of $4,641 million including working capital and other adjustments. Substantially all of ACC's land and production base is located in Western Canada and consists of natural gas weighted assets. The operating results of ACC have been consolidated with the results of the Company effective November 2006. This acquisition increased fourth quarter 2006 sales volumes by approximately 44,800 boe/d. Natural gas production from the ACC properties averaged 354 mmcf/d for the two months of November and December.

The Company expects that consolidated net earnings will continue to reflect significant quarterly volatility due to the impact of risk management activities, stock-based compensation expense and fluctuations in foreign exchange rates.

The Company's commodity hedging program reduces the risk of volatility in commodity price markets and supports the Company's cash flow for its capital expenditure program throughout the Horizon Oil Sands Project ("Horizon Project") construction period. This program allows for the hedging of up to 75% of the near 12 months budgeted production, up to 50% of the following 13 to 24 months estimated production and up to 25% of production expected in months 25 to 48. For the purpose of this program, the purchase of crude oil put options is in addition to the above parameters. In accordance with the policy, approximately 65% of expected crude oil volumes and approximately 75% of expected natural gas volumes have been hedged for 2007. In addition, 77,000 bbl/d of crude oil volumes are protected by put options for 2007 at a strike price of US$60.00 per barrel. The Company is extending its hedge program into 2008 whereby 150,000 bbl/d of crude oil volumes have been hedged (100,000 bbl/d of price collars with a US$60.00 floor and 50,000 bbl/d of put options with a US$55.00 strike price). In addition, 900,000 GJ/d of natural gas volumes have been hedged through the use of price collars for the first quarter of 2008 (400,000 GJ/d with a floor of $7.00 and 500,000 GJ/d with a floor of $7.50).

As effective as the Company's hedges are against reference commodity prices, a portion of the derivative financial instruments entered into by the Company do not meet the requirements for hedge accounting under GAAP due to currency, product quality and location differentials (the "non-designated hedges"). The Company is required to mark-to-market these non-designated hedges based on prevailing forward commodity prices in effect at the end of each reporting period. Accordingly, the unrealized risk management asset reflects, at December 31, 2006, the implied price differentials for the non-designated hedges for future periods. The cash settlement amount of the risk management financial derivative instruments may vary materially depending upon the underlying crude oil and natural gas prices at the time of final settlement of the financial derivative instruments, as compared to their mark-to-market value at December 31, 2006.

Due to the changes in crude oil and natural gas forward pricing, and the reversal of prior year unrealized losses, the Company recorded a net unrealized gain of $1,013 million ($674 million after-tax) on its risk management activities for the year ended December 31, 2006, including an unrealized gain of $241 million ($166 million after-tax) for the three months ended December 31, 2006. Mark-to-market unrealized gains and losses do not impact the Company's current cash flow or its ability to finance ongoing capital programs. The Company continues to believe that its risk management program meets its objective of securing funding for its capital projects and does not intend to alter its current strategy of obtaining price certainty for its crude oil and natural gas sales.

The Company also recorded a $139 million ($95 million after-tax) stock-based compensation expense for the year ended December 31, 2006 in connection with the 8% increase in the Company's share price, and a $176 million ($120 million after-tax) stock-based compensation expense as a result of the 22% increase in the Company's share price for the three months ended December 31, 2006 (Company's share price as at: December 31, 2006 - C$62.15; September 30, 2006 - C$50.94; December 31, 2005 - C$57.63). As required by GAAP, the Company records a liability for potential cash payments to settle its outstanding employee stock options each reporting period, based on the difference between the exercise price of the stock options and the market price of the Company's common shares, pursuant to a graded vesting schedule. The liability is revalued each quarter to reflect the changes in the market price of the Company's common shares and the options exercised or surrendered in the period, with the net change recognized in earnings, or capitalized as part of the Horizon Project during the construction period. The stock-based compensation liability reflected the Company's potential cash liability should all the vested options be surrendered for a cash payout at the market price on December 31, 2006. In periods when substantial share price changes occur, the Company's net earnings are subject to significant volatility. The Company utilizes its stock-based compensation plan to attract and retain employees in a competitive environment. All employees participate in this plan.

Cash flow from operations for the year ended December 31, 2006 decreased slightly to $4,932 million from $5,021 million for the year ended December 31, 2005. The decrease was primarily due to decreased natural gas pricing, increased realized risk management losses, increased production expense and the impact of a stronger Canadian dollar relative to the US dollar. These factors were partially offset by stronger benchmark crude oil pricing and increased crude oil and NGLs and natural gas sales volumes.

Cash flow from operations in the fourth quarter of 2006 decreased to $1,293 million from $1,490 million for the fourth quarter of 2005 and $1,313 million in the prior quarter. The decrease from the fourth quarter of 2005 was primarily due to decreased natural gas pricing, increased production expense and the impact of a stronger Canadian dollar relative to the US dollar. These factors were offset by the impact of increased crude oil pricing, increased crude oil and NGLs and natural gas sales volumes and decreased realized risk management losses.

Total production before royalties increased 5% to average a record 580,724 boe/d for the year ended December 31, 2006 from 552,960 boe/d for the year ended December 31, 2005. Production for the fourth quarter of 2006 increased 6% to 613,764 boe/d from 577,505 boe/d in the fourth quarter of 2005 and increased 9% from 561,152 boe/d in the prior quarter.

The increase in crude oil and NGLs production for the year and three months ended December 31, 2006 from the comparable periods reflected increased production from the Company's Primrose thermal projects, the positive results from the Pelican Lake waterflood project, additional production volumes as a result of the ACC acquisition, development of West and East Espoir and the full year's impact of production from the Baobab Field located offshore Cote d'Ivoire. Production from the Baobab Field commenced August 2005.

The increase in natural gas production for the year and three months ended December 31, 2006 from the comparable periods primarily reflected additional natural gas production as a result of the ACC acquisition. Natural gas production from the ACC properties averaged 354 mmcf/d for the two months of November and December. The increase was partially offset by declining production due to the Company's strategic reduction in natural gas drilling activity and increased North America crude oil drilling, made in response to sustained low natural gas prices and inflationary cost pressures.

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