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Press release from CNW Group

MEG Energy announces 2010 fourth quarter financial and operating results and December 31, 2010 reserve and resource estimates

Thursday, February 03, 2011

MEG Energy announces 2010 fourth quarter financial and operating results and December 31, 2010 reserve and resource estimates05:00 EST Thursday, February 03, 2011CALGARY, Feb. 3 /CNW/ - MEG Energy Corp. ("MEG" or the "Corporation") reported fourth quarter 2010 net earnings of $46.5 million ($0.24 per share, diluted) compared to a net loss of $16.0 million (loss of $0.11 per share) in the fourth quarter of 2009. Operating earnings in the fourth quarter 2010 were $19.5 million ($0.10 per share) compared to an operating loss of $13.9 million (loss of $0.09 per share) in the fourth quarter of 2009.Cash flow from operations for the fourth quarter of 2010 was $74.1 million ($0.38 per share) compared to a cash flow deficiency of $11.7 million (deficiency of $0.08 per share) in the fourth quarter of 2009.The increase in earnings and cash flow during the fourth quarter was primarily due to higher production and lower operating costs. During the fourth quarter of 2010 production averaged 27,744 barrels of bitumen per day, approximately 10% above the nominal design capacity of the facilities. The steam to oil ratio ("SOR") in the fourth quarter of 2010 was 2.3, compared with a design SOR of 2.8. In the fourth quarter 2009 Christina Lake Phase 2 had just commenced operations and production averaged 5,933 barrels of bitumen per day. Operating costs during the fourth quarter of 2010 averaged $14.22 per barrel, including non-energy costs of $9.35 per barrel."I am very proud of what we have accomplished in the fourth quarter and the full year. Christina Lake continues to exceed our expectations both from production and operating cost perspectives. Considerable momentum has been developed as we enter 2011," said Bill McCaffrey, Chairman, President and CEO.MEG also reported that GLJ Petroleum Consultants Ltd. ("GLJ"), a leading independent reservoir engineering firm, has completed an evaluation of the Corporation's reserves and recoverable resources effective as of December 31, 2010. The estimates of reserves and resources were prepared in accordance with National Instrument 51-101. Proved bitumen reserves increased to 606 million barrels, an increase of 10% compared with December 31, 2009, while proved plus probable reserves increased by 13% to 1,919 million barrels. The pre-tax present value of the future net cash flows of the proved reserves and proved plus probable reserves, discounted at 10% per annum, were $5.4 billion and $12.1 billion, respectively. The best estimate of contingent resources remained substantially unchanged at 3,716 million barrels. A summary of GLJ's report follows the unaudited financial statements in this news release.The strong finish to the year reinforces the production and operating cost guidance for 2011. Production volumes are expected to average between 25,000 and 27,000 bbls/day taking into account the anticipated plant turnaround in September 2011. Non-energy operating costs are budgeted to continue to trend downward with the guidance for 2011 being in the $9 to $11/bbl range.Capital investment for 2011 is budgeted to be approximately $900 million with the majority being invested towards MEG's strategic plan of growing bitumen production capacity to 260,000 bbls/day by 2020.OPERATIONAL AND FINANCIAL HIGHLIGHTSThe following table summarizes selected financial and operational information of the Corporation as at and for the periods indicated: << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($000 except per share amounts and as noted) 2010 2009 2010 2009 ------------------------------------------------------------------------- Bitumen production - bbls/d 27,744 5,933 21,257 3,467 Bitumen realization - $/bbl 51.43 51.70 51.76 45.01 Operating costs: Energy 4.87 18.89 6.47 12.18 Non-energy 9.35 33.15 14.39 43.62 Total operating costs - $/bbl 14.22 52.04 20.86 55.80 Steam to oil ratio 2.3 4.9 2.5 3.9 Operating earnings (loss)(1) 19,456 (13,940) 13,117 (39,944) Per share, diluted(1) 0.10 (0.09) 0.07 (0.28) Net income (loss) 46,498 (16,028) 40,097 51,176 Per share, basic 0.25 (0.11) 0.23 0.37 Per share, diluted 0.24 (0.11) 0.22 0.36 Cash flow from operations(1) 74,119 (11,695) 161,846 (32,461) Per share, diluted(1) 0.38 (0.08) 0.88 (0.23) Capital investment 147,438 64,140 494,630 351,342 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Operating earnings, cash flow from operations and the related per share amounts do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. The Corporation uses these non-GAAP measurements for its own performance measures and to provide its shareholders and investors with a measurement of the Corporation's ability to internally fund future growth expenditures. These "Non- GAAP Measurements" are reconciled to net income (loss) in accordance with Canadian GAAP under the heading "Non-GAAP Measurements". >>Bitumen production increased to 27,744 barrels per day for the three months ended December 31, 2010 compared to 5,933 barrels per day for the three months ended December 31, 2009. For the year ended December 31, 2010 bitumen production averaged 21,257 barrels per day compared to 3,467 barrels per day in 2009. The increase in production is due to the increased volumes from the ramp up of Phase 2 of the Christina Lake Project.Operating costs for the three months ended December 31, 2010 were $14.22 per barrel compared to $52.04 per barrel for the same period in 2009. For the year ended December 31, 2010 operating costs were $20.86 per barrel compared to $55.80 per barrel in 2009. Operating costs per barrel decreased primarily as a result of the increase in production as a result of the ramp-up of the Christina Lake Phase 2 facility.The average SOR for the three months ended December 31, 2010 was 2.3 compared to an SOR of 4.9 for the three months ended December 31, 2009. For the year ended December 31, 2010 the average SOR was 2.5 compared to an average SOR of 3.9 in 2009. The SOR has decreased throughout 2010 as the Phase 2 well pairs have quickly progressed through the circulation phase and entered into normal operations. The early success of the production ramp-up, and improved SOR, has enabled the Corporation to performance test the integrated Phase 1 and 2 facilities and exceed the plant design production capacity.Operating earnings for the three months ended December 31, 2010 were $19.5 million compared to an operating loss of $13.9 million for the three months ended December 31, 2009, an increase of $33.4 million. Operating earnings of $13.1 million for the year ended December 31, 2010 represent an increase of $53.0 million from a $39.9 million loss for the same period in 2009. The increase in operating earnings primarily resulted from higher production volumes related to the ramp-up of the Christina Lake Phase 2 operations.Net income for the fourth quarter of 2010 was $46.5 million compared to a net loss of $16.0 million for the fourth quarter of 2009. Net income for the year ended December 31, 2010 was $40.1 million compared to $51.2 million in 2009. This change was primarily attributable to fluctuations in the rate of exchange between the Canadian and U.S. dollar in translating the Corporation's U.S. dollar denominated debt. During the fourth quarter of 2010 there was an unrealized $35.3 million gain for the translation of the debt compared to an $18.5 million unrealized gain during the same period in 2009. For the year ended December 31, 2010 there was an unrealized foreign exchange gain of $52.2 million for the translation of the debt compared to a $127.3 million unrealized gain in 2009. The reduction in the foreign exchange gains compared to 2009 is offset by the fact that net income during the three months and year ended December 31, 2009 only included one month of income from operations. Effective December 1, 2009, the Corporation commenced planned principal operations and ceased capitalizing blend revenue, operating costs and interest costs for Phases 1 and 2 of the Christina Lake Project.Cash flow from operations for the three months ended December 31, 2010 was $74.1 million, an increase of $85.8 million from the same period in 2009. Cash flow from operations for the year ended December 31, 2010 totalled $161.8 million, an increase of $194.3 million from 2009. The increase was the result of cash flows generated from the Phase 2 bitumen production.Capital investment during the fourth quarter of 2010 increased by $83.3 million compared to the fourth quarter of 2009 to $147.4 million. This increase is due mainly to increased investment on Christina Lake Phase 2B horizontal drilling and facilities engineering. Capital investment for the year ended December 31, 2010 increased from $351.3 million in 2009 to $494.6 million. The increase is due to increased investment on Christina Lake Phase 2B as well as the $42.5 million purchase of lands and assets associated with the Stonefell Terminal tank farm construction project and the $54.9 million purchase of undeveloped lands in the Surmont area.Non-GAAP MeasurementsThe following table reconciles the non-GAAP measurements "Operating earnings (loss)" and "Cash flow from operations" and "Cash operating netbacks" to "Net income (loss)", the nearest Canadian GAAP measure. Operating earnings (loss) is defined as net income (loss) as reported excluding the after-tax gains and losses on foreign exchange, risk management, loss on modification of long-term debt, and change in fair value of other assets. Cash flow from operations excludes realized risk management and foreign exchange losses and the net change in non-cash operating working capital while the Canadian GAAP measurement "Cash from operating activities" includes these items. Cash operating netback is comprised of petroleum and power sales less royalties, operating costs, cost of diluents and transportation and selling costs. Prior to December 1, 2009 these items were capitalized as the Corporation had not commenced planned principal operations. << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- Non-GAAP Measurements ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Net income (loss) 46,498 (16,028) 40,097 51,176 Add (deduct): Foreign exchange gains, net of tax(1) (30,122) (15,883) (43,316) (116,817) Risk management losses, net of tax(2) 3,080 2,007 16,336 7,577 Change in fair value of other assets, net of tax(3) - - - 2,156 Loss on modification of long- term debt, net of tax(4) - 15,964 - 15,964 ------------------------------------------------------------------------- Operating earnings (loss) 19,456 (13,940) 13,117 (39,944) Add (deduct) non-cash items: Stock-based compensation 4,794 2,941 14,439 12,912 Depletion, depreciation and accretion 41,688 2,592 124,801 3,103 Other 30 119 170 336 Future income taxes, operating 8,151 (3,407) 9,319 (8,868) ------------------------------------------------------------------------- Cash flow from operations 74,119 (11,695) 161,846 (32,461) Add (deduct): Net operating loss capitalized - 680 - (21,010) Interest income (3,764) (367) (7,933) (2,572) General and administrative 10,761 5,266 36,427 24,295 Research and development 817 1,625 5,384 4,690 Interest expense 11,074 3,306 44,591 4,183 ------------------------------------------------------------------------- Cash operating netback 93,007 (1,185) 240,315 (22,875) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Foreign exchange gains result primarily from the translation of US dollar denominated long-term debt and debt service reserve to period-end exchange rates. (2) Risk management losses result from the Corporation's interest rate swaps entered into to fix a portion of its variable rate long-term debt. (3) Change in fair value of other assets results from fair value changes in certain long-term investments. (4) Loss on modification of long-term debt results from modifications to the Corporation's senior secured credit facility on December 23, 2009. >>SUMMARY OF QUARTERLY RESULTSThe following table summarizes selected financial information for the Corporation for the preceding eight quarters: << 2010 2009 --------------------------- --------------------------- ($ millions, except per share amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 ------ ------ ------ ------ ------ ------ ------ ------ Revenue, net of royalties 246.3 155.0 210.5 126.4 23.8 0.4 0.5 1.3 Net income (loss) 46.5 25.7 (31.7) (0.4) (16.0) 44.1 56.7 (33.6) Per share - basic 0.25 0.14 (0.19) 0.00 (0.11) 0.31 0.41 (0.26) Per share - diluted 0.24 0.14 (0.19) 0.00 (0.11) 0.30 0.40 (0.26) >>Revenue for the first 11 months in 2009 was primarily from interest earned on the investment of surplus cash. Commencing December 2009, revenues also include the revenue from the sale of bitumen blend and power. Effective December 1, 2009, the Corporation commenced planned principal operations and ceased capitalizing blend revenue, operating costs and interest costs for Phases 1 and 2 of the Christina Lake Project.Net income (loss) during the periods noted were impacted by foreign exchange gains and losses attributable to fluctuations in the rate of exchange between the Canadian and U.S. dollar in translating the Corporation's U.S. dollar denominated debt, risk management activities for interest rate swaps, and costs for modification of long-term debt. The net income (loss) was also positively impacted by the inclusion of blend revenue, operating costs and interest costs for Phases 1 and 2 of the Christina Lake Project as planned principal operations commenced December 1, 2009 and the Corporation ceased capitalizing these items.The following table shows the Corporation's results and industry commodity pricing information on a quarterly basis to assist in understanding the impact of commodity prices and foreign exchange rates on the Corporation's financial results: << ------------------------------------------------------------------------- Year ended December 31 2010 ------------------------------------------------------------------------- 2010 2009 Q4 Q3 Q2 Q1 ------------------------------------------------ Commodity Prices (Average Prices) Crude oil prices West Texas Intermediate (WTI) US$/bbl 79.52 61.80 85.13 76.20 78.03 78.71 Western Canadian Select (WCS) CDN$/bbl 67.23 58.66 67.87 62.94 65.60 72.51 Differential - WTI/WCS (CDN$/bbl) 14.69 11.89 18.35 16.24 14.59 9.42 Differential - WTI/WCS (%) 18.0% 17.0% 21.0% 20.5% 18.2% 11.5% Natural gas prices AECO (CDN$/mcf) 4.11 4.12 3.56 3.70 3.84 5.33 Electric power prices Alberta Power Pool average price (CDN$/MW) 50.91 47.80 45.95 35.77 81.15 40.78 Foreign exchange rates Average Canadian/ U.S. dollar exchange rate 1.0301 1.1415 1.0128 1.0391 1.0276 1.0409 Corporation results Blend Sales (CDN$/bbl) 63.03 53.40 63.95 60.84 60.94 68.06 Differential - WTI/ Blend (CDN$/bbl) 18.88 17.14 22.27 18.33 19.25 13.88 Differential - WTI/Blend (%) 23.0% 24.3% 25.8% 23.2% 24.0% 16.9% Diluent cost (CDN$/bbl) 87.27 73.56 89.95 83.46 86.20 88.56 Bitumen sales (CDN$/bbl) 51.76 45.01 51.43 51.73 48.73 58.10 Bitumen sales (bbls/d)(1) 21,292 3,416 27,648 19,376 24,562 13,447 ------------------------------------------------------------------------- --------------------------------------------------------- 2009 --------------------------------------------------------- Q4 Q3 Q2 Q1 -------------------------------- Commodity Prices (Average Prices) Crude oil prices West Texas Intermediate (WTI) US$/bbl 76.19 68.30 59.62 43.08 Western Canadian Select (WCS) CDN$/bbl 67.66 63.74 60.64 42.60 Differential - WTI/WCS (CDN$/bbl) 12.82 11.21 8.95 11.05 Differential - WTI/WCS (%) 15.9% 15.0% 12.9% 20.6% Natural gas prices AECO (CDN$/mcf) 4.21 3.01 3.64 5.61 Electric power prices Alberta Power Pool average price (CDN$/MW) 46.06 49.49 32.30 63.35 Foreign exchange rates Average Canadian/ U.S. dollar exchange rate 1.0563 1.0974 1.1672 1.2453 Corporation results Blend Sales (CDN$/bbl) 61.11 58.36 55.37 33.22 Differential - WTI/ Blend (CDN$/bbl) 19.37 16.59 14.21 20.43 Differential - WTI/Blend (%) 24.1% 22.1% 20.4% 38.1% Diluent cost (CDN$/bbl) 83.79 74.52 65.78 59.10 Bitumen sales (CDN$/bbl) 51.70 52.08 50.95 21.94 Bitumen sales (bbls/d)(1) 5,920 2,493 2,136 3,093 --------------------------------------------------------- --------------------------------------------------------- (1) The Corporation completed a planned plant turnaround in the third quarter of 2010. >>RESULTS OF OPERATIONSSince the commencement of Phase 2 steaming operations in August 2009 production at the integrated Phase 1 and Phase 2 facilities has increased to average 27,744 bbls/d during the fourth quarter of 2010, exceeding the design capacity of 25,000 bbls/d. The average SOR for the three months ended December 31, 2010 was 2.3 compared to an SOR of 4.9 for the three months ended December 31, 2009. For the year ended December 31, 2010 the average SOR was 2.5 compared to an average SOR of 3.9 in 2009. SOR is an important efficiency indicator which measures the amount of steam that is injected into the reservoir in relation to bitumen produced. A lower SOR indicates a more efficient steam assisted gravity drainage ("SAGD") process. SORs are higher in the start-up period than in steady state operations due to the initial steam circulation period and lower initial production rates during ramp-up.The Corporation's 85 MW cogeneration facility produces approximately 70% of the steam for Phase 1 and 2 SAGD operations and is operating near capacity. MEG's processing facility is utilizing the heat produced by the cogeneration facility and approximately 8 - 12 MW of the power generated. Beginning in October 2009, surplus power has been sold into the Alberta Power Pool electricity grid.The following table summarizes the Corporation's results of operations for the periods indicated:Operating Summary << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- Cash operating netback ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Blend sales(1) 241,020 47,089 717,610 94,295 Cost of diluent(2) (110,199) (18,932) (315,350) (38,180) ------------------------------------------------------------------------- Bitumen sales 130,821 28,157 402,260 56,115 Transportation and other selling costs (3,197) (3,832) (12,480) (12,767) Royalties (5,777) (1,136) (16,521) (1,705) ------------------------------------------------------------------------- Net bitumen revenue 121,847 23,189 373,259 41,643 Operating costs - energy (12,384) (10,289) (50,288) (15,183) Operating costs - non-energy (23,786) (18,056) (111,853) (54,383) Power sales 7,330 3,971 29,197 5,048 ------------------------------------------------------------------------- Cash operating netback(3) 93,007 (1,185) 240,315 (22,875) Less capitalized(4) - 680 - (21,010) ------------------------------------------------------------------------- Cash operating netback in statement of operations(4) 93,007 (1,865) 240,315 (1,865) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- Production and Sales Volume Summary (bbls/d) 2010 2009 2010 2009 ------------------------------------------------------------------------- Blend sales(1) 40,964 8,376 31,192 4,838 Diluents(2) (13,316) (2,456) (9,900) (1,422) ------------------------------------------------------------------------- Bitumen sales 27,648 5,920 21,292 3,416 (Increase) decrease in inventory 96 13 (35) 51 ------------------------------------------------------------------------- Total bitumen production 27,744 5,933 21,257 3,467 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Power sales (MWh) 163,198 89,434 585,476 98,914 Power realization (CDN$/MWh) 44.91 44.40 49.87 51.97 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- Cash operating netback ($ per barrel) 2010 2009 2010 2009 ------------------------------------------------------------------------- Bitumen sales 51.43 51.70 51.76 45.01 Transportation and other selling costs (1.26) (7.04) (1.61) (10.24) Royalties (2.27) (2.09) (2.13) (1.37) ------------------------------------------------------------------------- Net bitumen revenue 47.90 42.57 48.02 33.40 Operating costs - energy (4.87) (18.89) (6.47) (12.18) Operating costs - non-energy (9.35) (33.15) (14.39) (43.62) Power sales 2.88 7.29 3.76 4.05 ------------------------------------------------------------------------- Cash Operating Netback(3) 36.56 (2.18) 30.92 (18.35) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Bitumen produced at the Christina Lake Project is mixed with purchased diluent and sold as bitumen blend. Diluent is a light hydrocarbon that improves the marketing and transportation quality of bitumen. (2) Diluent volumes purchased and sold have been deducted in calculating bitumen production revenue and production volumes sold. (3) Cash operating netbacks are calculated by deducting the related diluent, transportation and selling, field operating costs and royalties from revenues. Netbacks on a per-unit basis are calculated by dividing related production revenue, costs and royalties by bitumen production volumes. Netbacks do not have a standardized meaning prescribed by Canadian GAAP and, therefore, may not be comparable to similar measures by other companies. The non-GAAP measurement is widely used in the oil and gas industry as a supplemental measure of the company's efficiency and its ability to fund future growth through capital expenditures. "Cash operating netback" is reconciled to "net income (loss)" under the heading "Non-GAAP Measurements" above, the nearest Canadian GAAP measure. (4) Effective December 1, 2009, the Corporation commenced planned principal operations and ceased capitalizing net operating costs. >>Bitumen sales in the three months ended December 31, 2010 were $130.8 million compared to $28.2 million for the same period in 2009. The increase of $102.6 million is primarily due to higher production volumes from the ramp-up of Christina Lake Phase 2 operations. WTI averaged US$85.13 per barrel (C$86.22/bbl) in the fourth quarter of 2010 compared to US$76.19 per barrel (C$80.48/bbl) in the same period in 2009. Revenue for the Corporation's blend of bitumen and diluent averaged $63.95 per barrel during the three months ended December 31, 2010 compared to $61.11 per barrel for the same period in 2009.Bitumen sales in the year ended December 31, 2010 were $402.3 million compared to $56.1 million for the same period in 2009. The increase of $346.2 million is due to higher production volumes from the start up of Christina Lake Phase 2 and higher selling prices. WTI averaged US$79.52 per barrel (C$81.91/bbl) in 2010 compared to US$61.80 per barrel (C$70.54/bbl) in 2009. Blend revenue averaged $63.03 per barrel for the year ended December 31, 2010 compared to $53.40 per barrel in 2009.Energy operating costs represent the cost of gas purchased to operate the Corporation's once through steam generators and the cogeneration facility. Non-energy operating costs represent all other non-natural gas related operating expenses. Energy operating costs have decreased from $18.89 per barrel for the fourth quarter of 2009 to $4.87 per barrel for the fourth quarter of 2010 and from $12.18 per barrel for the year ended December 31, 2009 to $6.47 per barrel for the year ended December 31, 2010. Non-energy operating costs were $9.35 per barrel for the fourth quarter of 2010 compared to $33.15 per barrel for the fourth quarter of 2009 and $14.39 per barrel for the year ended December 31, 2010 compared to $43.62 per barrel for the year ended December 31, 2009. Operating costs per barrel have decreased in 2010 primarily as a result of the increase in production from the ramp-up of Christina Lake Phase 2.Power sales for the three months ended December 31, 2010 were $7.3 million compared to $4.0 million for the same period in 2009. During the fourth quarter of 2010 the Corporation realized an average price of $44.91 per megawatt hour compared to the Alberta Pool average of $45.95. Power sales for the year ended December 31, 2010 were $29.2 million compared to $5.0 million in 2009. During the year ended December 31, 2010 the Corporation realized a price of $49.87 per megawatt hour compared to the Alberta Pool average price of $50.91 per megawatt hour. There will be variances to the Alberta Pool average price benchmark as it is based on the average daily price while power sales are priced on an hourly basis and can vary significantly each hour during the day.During commissioning and start up it takes time for the reservoir to respond and for operations to work through the normal processing and treating issues associated with a new facility. Since Phase 1 was a pilot plant and Phase 2 was ramping-up production through 2009 and into 2010, current operating netback per barrel does not yet reflect the economies associated with a steady state facility operating at its design capacity. Operating cost per barrel has decreased in 2010 compared to 2009 as fixed costs are spread over the higher production volumes during this period. The Corporation anticipated volatility in operating results with the start up of Phase 2 but expects the volatility to become less pronounced as steady-state operations are achieved.General and Administrative Costs << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- G&A Expense 10,737 5,266 36,403 24,295 Capitalized G&A 2,952 1,993 11,258 9,576 ------------------------------------------------------------------------- Total G&A Costs 13,689 7,259 47,661 33,871 ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>General and administrative costs for the three months ended December 31, 2010 totalled $13.7 million, compared with $7.3 million for the same period in 2009. General and administrative costs for the year ended December 31, 2010 totalled $47.7 million, compared with $33.9 million in 2009. The increase in costs primarily resulted from the planned growth in the Corporation's professional staff and costs to support the operations and development of its oil sands assets. The head office employee headcount grew from 147 as of December 31, 2009 to 184 at December 31, 2010. For the year ended December 31, 2010 the Corporation capitalized salaries related to capital investment of $11.3 million (2009 - $9.6 million).Stock-based CompensationStock-based compensation expense for the three months ended December 31, 2010 was $4.8 million compared to $2.9 million for the same period in 2009. Stock-based compensation expense for the year ended December 31, 2010 was $14.4 million compared to $12.9 million for the same period in 2009. For the year ended December 31, 2010 the Corporation capitalized $3.7 million (2009 - $3.8 million) of stock-based compensation to property, plant and equipment.Foreign Exchange Loss (Gain) << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Long-term debt (35,268) (18,529) (52,186) (127,258) Debt service reserve 913 - 2,195 3,832 US$ denominated cash and cash equivalents 457 811 1,445 4,843 Other (416) (55) (509) (1,524) ------------------------------------------------------------------------- Foreign exchange loss(gain) (34,314) (17,773) (49,055) (120,107) ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- US$ - Canadian $ exchange rate As at December 31, 2010 2009 2008 ------------------------------------------------------------------------- C$ equivalent of 1 US dollar 0.9946 1.0466 1.2246 ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>The net foreign exchange gains for the three months and year ended December 31, 2010 were primarily due to the strengthening of the Canadian dollar with respect to the US dollar and higher US dollar debt outstanding in 2010.In December 2009, the Corporation increased its senior secured term loan by US$300 million. In the fourth quarter of 2010 the Canadian dollar strengthened against the US dollar by $0.03 while in the same period of 2009 it strengthened by $0.02. For the year ended December 31, 2010 the Canadian dollar strengthened against the US dollar by $0.05 while in 2009 it strengthened by $0.18.Risk Management Loss << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Realized loss on interest rate swaps 8,625 4,945 34,412 17,180 Unrealized fair value gain on interest rate swaps (8,763) (4,266) (32,671) (14,753) Amortization of unrealized loss on interest rate swaps from accumulated other comprehensive income 4,246 1,997 20,041 7,676 ------------------------------------------------------------------------- Total risk management loss 4,108 2,676 21,782 10,103 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>The Corporation realized an increase in interest costs due to the interest rate swaps which have been charged to operations as risk management loss. The Corporation hedged, until December 31, 2010, the interest rate on US$700 million of its floating rate debt by swapping LIBOR for an average fixed rate of 5.05%. For the three months ended December 31, 2010, the average LIBOR rate was 0.29% which was consistent with the average rate for the same period in 2009. For the year ended December 31, 2010 the average LIBOR rate was 0.35% compared to 0.89% for the year ended December 31, 2009.The unrealized fair value gain on the interest rate swaps is due to the change in the fair value of the interest swaps. In the fourth quarter of 2010 the fair value of the interest rate swap liability decreased $8.8 million compared to $4.3 million for the same period in 2009. For the year ended December 31, 2010 the fair value of the interest rate swap liability decreased by $32.7 million compared to $14.8 million for the same period in 2009. The fair value of the interest rate swaps declined over the periods noted due to the shorter term to expiry of the contracts. As at December 31, 2010 the interest rate swap contracts have expired and there is no further liability associated with the contracts.The amortization of the unrealized loss on interest rate swaps from accumulated other comprehensive income is a result of the Corporation previously applying hedge accounting to its interest rate swap contracts. Hedge accounting was subsequently discontinued as the hedges were no longer effective. As at December 31, 2010, all amounts remaining in accumulated other comprehensive income related to these swaps have been amortized into earnings.Interest Expense << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Total interest expense 16,315 10,228 65,484 44,607 Capitalized to property, plant and equipment (5,187) (6,803) (20,699) (40,088) ------------------------------------------------------------------------- Interest expense 11,128 3,425 44,785 4,519 ------------------------------------------------------------------------- ------------------------------------------------------------------------- >>Total interest expense in the three months and year ended December 31, 2010 increased compared to the same periods in 2009 primarily as a result of higher outstanding debt and higher interest rates on the Corporation's long-term debt. In December 2009 the Corporation increased its senior secured term loan by US$300.0 million.Effective December 1, 2009 the Corporation commenced planned principal operations and ceased capitalizing interest on the development of Phases 1 and 2 of the Christina Lake Project. Interest on the US$300 million incremental portion of the senior secured term loan associated with the development of Phase 2B of the Christina Lake Project continues to be capitalized.Depletion, Depreciation and AccretionDepletion of the Christina Lake Project developed assets commenced December 1, 2009 and was calculated using the unit-of-production method based on total estimated proved reserves. This equated to $16.01 per barrel of production for the three months ended December 31, 2010 and $15.76 per barrel of production for the year ended December 31, 2010. Prior to December 2009, there was no depletion and depreciation expense related to Phases 1 and 2 of the Christina Lake Project as planned principal operations had not yet commenced.Income TaxesFuture income tax expense for the three months ended December 31, 2010 was $11.3 million, an increase of $18.8 million from the same period in 2009. Future income tax expense for the year ended December 31, 2010 was $9.6 million compared to a future income tax recovery of $14.1 million in 2009.The Corporation's effective income tax rate is primarily impacted by permanent differences and variances in valuation reserves. The significant permanent differences are: << - The non-taxable portion of capital foreign exchange gains and losses on the translation of the US dollar denominated debt. For the year ended December 31, 2010 the non-taxable foreign exchange gain was $26.1 million compared to $60.4 million for the year ended December 31, 2009. - The non-taxable portion of stock-based compensation. For the year ended December 31, 2010, non-taxable stock-based compensation was $14.4 million compared to $12.9 million for the year ended December 31, 2009. >>The Corporation is not currently taxable. As of December 31, 2010, the Corporation had approximately $3.1 billion of available tax pools and had recognized a net future tax liability of $22.2 million. In addition, at December 31, 2010 the Corporation had $247.2 million of capital investment in respect of incomplete projects which will be added to available tax pools upon completion of the projects.CAPITAL INVESTINGThe following table summarizes the capital investments for the periods presented. << ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- Summary of capital investment ($000) 2010 2009 2010 2009 ------------------------------------------------------------------------- Christina Lake Project: Resource exploration and delineation 2,591 1,341 25,836 6,305 Horizontal drilling 36,910 3,586 36,910 6,867 Facilities, procurement and construction 80,705 44,945 241,621 255,328 Other 145 283 8,653 1,908 ------------------------------------------------------------------------- Total Christina Lake Project 120,351 50,155 313,020 270,408 Surmont and Growth Properties 2,306 605 15,253 1,812 Land and other acquisitions 833 3 100,961 136 Capitalized interest and fees 4,635 6,362 18,633 37,790 Other 15,302 5,086 36,728 33,729 ------------------------------------------------------------------------- Total cash investments 143,427 62,211 484,595 343,875 Non-cash investments 4,011 1,929 10,035 7,467 ------------------------------------------------------------------------- Total capital investment 147,438 64,140 494,630 351,342 ------------------------------------------------------------------------- >>The Corporation invested cash of $143.4 million during the fourth quarter of 2010 compared to $62.2 million during the fourth quarter of 2009. During 2010, the Corporation invested cash totalling $484.6 million compared with $343.9 million in the same period in 2009. Capital investment in 2010 was focused on Christina Lake Project Phase 2B development and resource delineation at Christina Lake and on the Growth Properties.Christina Lake ProjectDuring the year ended December 31, 2010 the Corporation drilled 66 core holes and six observation wells to assist in the determination of Phase 2B horizontal wells placement and further delineation of resources in the Christina Lake leases. The Phase 2B horizontal drilling program was initiated in the fourth quarter of 2010. Facilities investment in 2010 was directed towards Phase 2B detailed engineering and commencing the purchase of major equipment, installation of electric submersible pumps, and maintenance and reliability of the Phase 2 facility. As at December 31, 2010, the detailed engineering of Phase 2B was 41% complete and capital commitments for 90% of all equipment orders were in place. On November 30, 2010, the Corporation's board of directors approved the 35,000 bpd Phase 2B expansion with a cost estimate of $1.4 billion.Effective December 1, 2009 management determined that planned principal operations at Christina Lake had commenced. The Corporation therefore ceased capitalizing net operating and interest costs associated with Phases 1 and 2 as of December 1, 2009. Net operating costs for the eleven months ended November 30, 2009 totalled $21.0 million and have been capitalized as they were incurred prior to the commencement of planned principal operations. (For further details, see the tables under the subheading "Operating Summary").Surmont and Growth PropertiesThe Corporation invested $15.3 million during the year ended December 31, 2010 to drill 24 core holes on the Growth Properties for increased resource definition and to evaluate source water quality near Surmont.Land and Other AcquisitionsDuring 2010 the Corporation invested $42.5 million to purchase lands and assets associated with a tank farm construction project (the "Stonefell Terminal"), located east of the Access Pipeline Sturgeon Terminal. Once construction of the Stonefell Terminal is complete, it is anticipated to have a storage capacity of 900,000 barrels. The Corporation also acquired an additional 8,320 acres (13 square miles) of undeveloped oil sands leases in the Surmont area for $54.9 million.Non-CashNon-cash capital investment is comprised of capitalized financing transaction costs, capitalized stock based-compensation and amounts capitalized in respect of asset retirement obligations.Forward-Looking InformationThis news release may contain forward-looking information including but not limited to: expectations of future production, revenues, cash flow, operating costs, steam-oil-ratios, reliability, profitability and capital investments; estimates of reserves and resources; the anticipated reductions in operating costs as a result of optimization and scalability of certain operations; the anticipated capital requirements, timing for receipt of regulatory approvals, development plans, timing for completion, production capacities and performance of the Access Pipeline, the Stonefell Terminal, the future phases and expansions of the Christina Lake project, the Surmont project and MEG's other properties and facilities; and the anticipated sources of funding for operations and capital investments. Such forward-looking information is based on management's expectations regarding future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities. Such forward-looking information also involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: risks associated with financial market volatility, the risks associated with the oil and gas industry (e.g. operational risks in development; exploration and production; delays or changes in plans with respect to exploration or development projects or capital investments; access to markets and to transportation infrastructure, the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses; health, safety and environmental risks; the risk of legislative and regulatory changes to, amongst other things, taxes, land use, royalties and environmental laws), the risk of commodity price and foreign exchange rate fluctuations; and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Christina Lake project and the development of the Corporation's other projects and facilities. Although MEG believes that the assumptions used in such forward-looking information are reasonable, there can be no assurance that such assumptions will be correct. Accordingly, readers are cautioned that the actual results achieved may vary from the forward-looking information provided herein and that the variations may be material. Readers are also cautioned that the foregoing list of assumptions, risks and factors is not exhaustive. The forward-looking information included in this release is expressly qualified in its entirety by the foregoing cautionary statements. Unless otherwise stated, the forward-looking information included in this release is made as of February 3, 2011 and the Corporation assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by applicable securities laws.Statements in this release relating to reserves and resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the described reserves and resources, as the case may be, exist in the quantities predicted or estimated, and can be profitably produced in the future. Additional information regarding forward-looking information and the classification of MEG's reserves and resources is contained within the Corporation's public disclosure documents on file with Canadian securities regulatory authorities. In particular, for more information regarding forward-looking information see "Risk Factors" and "Industry Regulation" within MEG's supplemented prospectus dated July 28, 2010 (the "Prospectus") and for more information regarding the classification of MEG's estimated reserves and resources see "Independent Reserve and Resource Evaluation" within the Prospectus. MEG's public disclosure documents may be accessed through the SEDAR website (www.sedar.com), at MEG's website (www.megenergy.com) or by contacting MEG's investor relations department.Non-GAAP Financial MeasuresThis news release includes references to financial measures commonly used in the crude oil and natural gas industry, such as net bitumen revenue, operating earnings, cash flow from operations and cash operating netback. These financial measures are not defined by Canadian generally accepted accounting principles ("GAAP") and therefore are referred to as non-GAAP measures. The non-GAAP measures used by the Corporation may not be comparable to similar measures presented by other companies. The Corporation uses these non-GAAP measures to help evaluate its performance. Management considers net bitumen revenue, operating earnings and cash operating netback important measures as they indicate profitability relative to current commodity prices. Management uses cash flow from operations to measure the Corporation's ability to generate funds to finance capital expenditures and repay debt. These non-GAAP measures should not be considered as an alternative to or more meaningful than net income (loss), as determined in accordance with Canadian GAAP, as an indication of the Corporation's performance. The non-GAAP operating earnings, cash flow from operations and cash operating netback measures are reconciled to net income (loss), as determined in accordance with Canadian GAAP, under the heading "Non-GAAP Measurements" earlier in this news release. << MEG ENERGY CORP. Balance Sheet (Unaudited) ------------------------------------------------------------------------- As at December 31 ($ 000s) 2010 2009 ------------------------------------------------------------------------- Assets Current assets: Cash and cash equivalents (note 13) $ 1,224,446 $ 963,018 Short-term investments (note 2) 167,406 - Accounts receivable and other (note 3) 96,964 33,662 Inventories 6,173 5,560 Debt service reserve (note 4) - 102,359 ------------------------------------------------------------------------- 1,494,989 1,104,599 Restricted cash (note 5) - 12,810 Other assets (note 6) 7,492 7,743 Property, plant and equipment (note 7) 3,515,150 3,144,341 ------------------------------------------------------------------------- $ 5,017,631 $ 4,269,493 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and shareholders' equity Current liabilities: Accounts payable and accrued payables $ 144,378 $ 71,842 Current portion of deferred lease inducements (note 8) 292 - Risk management liability (note 12) - 32,671 Current portion of long-term debt (note 10) 10,065 10,593 ------------------------------------------------------------------------- 154,735 115,106 Deferred lease inducements (note 8) 3,185 - Long-term debt (note 10) 969,933 1,029,687 Asset retirement obligations (note 9) 16,793 14,297 Future income tax liability 22,238 14,290 ------------------------------------------------------------------------- 1,166,884 1,173,380 ------------------------------------------------------------------------- Commitments and contingencies (note 14) Shareholders' equity: Share capital (note 11) 3,821,579 3,137,696 Contributed surplus (note 11) 71,464 55,841 Deficit (42,296) (82,393) Accumulated other comprehensive loss - (15,031) ------------------------------------------------------------------------- 3,850,747 3,096,113 ------------------------------------------------------------------------- $ 5,017,631 $ 4,269,493 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to financial statements. MEG ENERGY CORP. Statement of Operations and Deficit (Unaudited) ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($ 000s except per share amounts) 2010 2009 2010 2009 ------------------------------------------------------------------------- Revenues: Petroleum sales $ 241,020 $ 21,380 $ 717,610 $ 21,380 Royalties (5,777) (573) (16,521) (573) Power sales 7,330 2,615 29,197 2,615 Interest 3,764 367 7,933 2,572 ------------------------------------------------------------------------- 246,337 23,789 738,219 25,994 ------------------------------------------------------------------------- Operating expenses: Operating costs 36,170 14,072 162,141 14,072 Cost of diluent 110,199 9,004 315,350 9,004 Transportation and selling costs 3,197 2,211 12,480 2,211 General and administrative 10,737 5,266 36,403 24,295 Stock-based compensation (note 11) 4,794 2,941 14,439 12,912 Research and development 817 1,625 5,384 4,690 Interest expense 11,128 3,425 44,785 4,519 Depletion, depreciation and accretion (notes 7 and 9) 41,688 2,592 124,801 3,103 ------------------------------------------------------------------------- 218,730 41,136 715,783 74,806 ------------------------------------------------------------------------- Revenues less operating expenses 27,607 (17,347) 22,436 (48,812) ------------------------------------------------------------------------- Other (gain) loss: Foreign exchange gain, net (34,314) (17,773) (49,055) (120,107) Risk management loss (note 12) 4,108 2,676 21,782 10,103 Loss on modification of long-term debt - 21,286 - 21,286 Change in fair value of other assets - - - 2,875 ------------------------------------------------------------------------- (30,206) 6,189 (27,273) (85,843) ------------------------------------------------------------------------- Income (loss) before income taxes 57,813 (23,536) 49,709 37,031 Future income tax expense (recovery) 11,315 (7,508) 9,612 (14,145) ------------------------------------------------------------------------- Net income (loss) 46,498 (16,028) 40,097 51,176 Deficit, beginning of period (88,794) (66,365) (82,393) (133,569) ------------------------------------------------------------------------- Deficit, end of period $ (42,296) $ (82,393) $ (42,296) $ (82,393) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings (loss) per share (note 13) Basic $ 0.25 $ (0.11) $ 0.23 $ 0.37 Diluted $ 0.24 $ (0.11) $ 0.22 $ 0.36 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes to financial statements. MEG ENERGY CORP. Statement of Other Comprehensive Income (Unaudited) ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($ 000s) 2010 2009 2010 2009 ------------------------------------------------------------------------- Net income (loss) $ 46,498 $ (16,028) $ 40,097 $ 51,176 ------------------------------------------------------------------------- Other comprehensive income, net of tax Gains (losses) on cash flow hedges (note 12) Unrealized loss on derivatives designated as cash flow hedges, net of taxes(1) - (219) - (1,532) Realized loss gain on derivatives designated as cash flow hedges capitalized, net of taxes(2) - 3,048 - 12,226 Amortization of balance in AOCI(3) 3,185 1,498 15,031 5,757 ------------------------------------------------------------------------- Other comprehensive income 3,185 4,327 15,031 16,451 ------------------------------------------------------------------------- Total comprehensive income (loss) $ 49,683 $ (11,701) $ 55,128 $ 67,627 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Statement of Accumulated Other Comprehensive Loss (Unaudited) ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($ 000s) 2010 2009 2010 2009 ------------------------------------------------------------------------- Balance, beginning of period $ (3,185) $ (19,358) $ (15,031) $ (31,482) Other comprehensive income, net of tax 3,185 4,327 15,031 16,451 ------------------------------------------------------------------------- Balance, end of period $ - $ (15,031) $ - $ (15,031) ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Net income tax expense, three months ended December 31, 2010 - nil, year ended December 31, 2010 - nil (three months ended December 31, 2009 - $73 benefit, year ended December 31, 2009 - $511 benefit) (2) Net income tax expense, three months ended December 31, 2010 - nil, year ended December 31, 2010 - nil (three months ended December 31, 2009 - $1,016 year ended December 31, 2009 - $4,075) (3) Net income tax expense, three months ended December 31, 2010 - $1,061 year ended December 31, 2010 - $5,010 (three months ended December 31, 2009 - $499, year ended December 31, 2009 - $1,919) See accompanying notes to financial statements. MEG ENERGY CORP. Statement of Cash Flows (Unaudited) ------------------------------------------------------------------------- Three months ended Year ended December 31 December 31 ------------------------------------------------------------------------- ($ 000s) 2010 2009 2010 2009 ------------------------------------------------------------------------- Cash provided by (used in): Operations: Net income (loss) $ 46,498 $ (16,028) $ 40,097 $ 51,176 Items not involving cash: Stock-based compensation 4,794 2,941 14,439 12,912 Depletion, depreciation and accretion 41,688 2,592 124,801 3,103 Unrealized net gain on foreign exchange (34,811) (17,718) (50,741) (122,415) Unrealized gain on risk management (4,517) (2,269) (12,630) (7,077) Loss on modification of long-term debt - 11,009 - 11,009 Future income tax expense (recovery) 11,315 (7,508) 9,612 (14,145) Other 30 119 170 3,211 Net change in non-cash operating working capital items (note 13) (45,551) 3,121 (50,143) 2,022 ------------------------------------------------------------------------- 19,446 (23,741) 75,605 (60,204) ------------------------------------------------------------------------- Investing: Purchase of property, plant and equipment (143,427) (62,211) (484,595) (343,875) Lease inducement (note 8) 3,501 - 3,501 - Change in debt service reserve 26,565 (105,813) 102,359 (50,146) Decrease (increase) in restricted cash (note 5) - 1,529 12,810 (12,810) Payments received on commercial paper and other 111 3,506 21 1,061 Net change in non-cash investing working capital items (note 13) (133,086) 2,470 (108,642) (21,398) ------------------------------------------------------------------------- (246,336) (160,519) (474,546) (427,168) ------------------------------------------------------------------------- Financing: Issue of shares 5,183 542,308 672,170 889,922 Issue of long-term debt - 298,907 - 332,945 Repayment of long-term debt (2,516) (2,648) (10,356) (8,780) ------------------------------------------------------------------------- 2,667 838,567 661,814 1,214,087 ------------------------------------------------------------------------- Foreign exchange loss on cash and cash equivalents held in foreign currency (457) (811) (1,445) (4,843) Increase (decrease) in cash and cash equivalents (224,680) 653,496 261,428 721,872 Cash and cash equivalents, beginning of period 1,449,126 309,522 963,018 241,146 ------------------------------------------------------------------------- Cash and cash equivalents, end of period (note 13)(1) $1,224,446 $ 963,018 $1,224,446 $ 963,018 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) Excludes $167,406 of short term investments as at December 31, 2010. See accompanying notes to financial statements. MEG ENERGY CORP. NOTES TO FINANCIAL STATEMENTS (Unaudited) Year ended December 31, 2010. Tabular amounts are expressed in $ 000 unless otherwise noted. ------------------------------------------------------------------------- MEG Energy Corp. (the "Corporation") was incorporated under the Alberta Business Corporations Act on March 9, 1999. The Corporation's shares trade on the Toronto Stock Exchange ("TSX") under the symbol "MEG". The Corporation owns a 100% interest in over 800 sections of oil sands leases in the Athabasca region of northern Alberta and is primarily engaged in a steam assisted gravity drainage oil sands development at its 80 section Christina Lake Regional Project ("Christina Lake Project"). The Corporation is using a staged approach to development. The development includes co-ownership of Access Pipeline ("Access"), a dual pipeline to transport diluent north from the Edmonton area to the Athabasca oil sands area and a blend of bitumen and diluent south from the Christina Lake Project into the Edmonton area. 1. BASIS OF PRESENTATION: These statements have been prepared in accordance with Canadian generally accepted accounting principles and reflect the same accounting policies and methods of computation as the financial statements for the year ended December 31, 2009. The disclosure herein is incremental to that included with the annual financial statements. The interim financial statements should be read in conjunction with the financial statements and the notes thereto for the year ended December 31, 2009. 2. SHORT-TERM INVESTMENTS: Short-term investments consist of commercial paper, money market deposits or similar instruments with a maturity of between 91 and 180 days from the date of purchase. 3. ACCOUNTS RECEIVABLE AND OTHER: --------------------------------------------------------------------- As at December 31 2010 2009 --------------------------------------------------------------------- Accounts receivable $ 94,170 $ 28,524 Deposits and advances 2,794 5,138 --------------------------------------------------------------------- $ 96,964 $ 33,662 --------------------------------------------------------------------- --------------------------------------------------------------------- 4. DEBT SERVICE RESERVE: Investments were held in a US dollar debt service reserve account to fund interest and principal payments associated with the senior secured credit facilities. As of December 31, 2010 the Corporation is no longer required to maintain a debt service reserve account. The US dollar denominated debt service account was translated into Canadian dollars at the period end exchange rate. The foreign exchange loss on the debt service reserve was $0.9 million for the three months ended December 31, 2010 and $2.0 million for the year ended December 31, 2010 (three months ended December 31, 2009 - $0.4 million gain, year ended December 31, 2009 - $3.4 million loss), and has been recognized in operations through foreign exchange. 5. RESTRICTED CASH: Restricted cash consisted of cash on deposit to collateralize letters of credit issued by the Corporation. In the second quarter of 2010 letters of credit previously issued were cancelled and replaced by letters of credit issued under the Corporation's US$185 million revolving credit facility (note 10). 6. OTHER ASSETS: --------------------------------------------------------------------- As at December 31 2010 2009 --------------------------------------------------------------------- MAV Notes (formerly asset-backed commercial paper) $ 4,707 $ 4,769 US Auction Rate Securities 2,785 2,974 --------------------------------------------------------------------- $ 7,492 $ 7,743 --------------------------------------------------------------------- --------------------------------------------------------------------- 7. PROPERTY, PLANT AND EQUIPMENT: --------------------------------------------------------------------- Accumulated depletion and Net book December 31, 2010 Cost depreciation value --------------------------------------------------------------------- Oil sands properties and equipment $ 3,624,092 $ 125,839 $ 3,498,253 Corporate assets 18,647 1,750 16,897 --------------------------------------------------------------------- $ 3,642,739 $ 127,589 $ 3,515,150 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- December 31, 2009 --------------------------------------------------------------------- Oil sands properties and equipment $ 3,144,945 $ 3,270 $ 3,141,675 Corporate assets 4,155 1,489 2,666 --------------------------------------------------------------------- $ 3,149,100 $ 4,759 $ 3,144,341 --------------------------------------------------------------------- --------------------------------------------------------------------- Effective December 1, 2009, planned principal operations of the Corporation's Christina Lake Project commenced and the Corporation began depleting the developed oil sands properties and equipment costs, excluding pipeline line fill costs of $40.2 million. Prior to the commencement of principal operations, operating costs net of revenues, were capitalized. The cost of undeveloped properties not subject to depletion as at December 31, 2010 was $1,371.5 million (December 31, 2009 - $1,194.6 million). In 2010 the Corporation capitalized $11.3 million (2009 - $9.6 million) of general and administrative expenses, $3.7 million (2009 - $3.8 million) of stock-based compensation costs and $20.7 million (2009 - $40.1 million) of interest and debt service costs relating to oil sands exploration and development activities. 8. DEFERRED LEASE INDUCEMENTS: Lease inducements applicable to the Calgary office lease are deferred and amortized as a reduction of general and administrative costs on a straight-line basis over the lease term. --------------------------------------------------------------------- As at December 31 2010 --------------------------------------------------------------------- Deferred lease inducements, beginning of year $ - Additions 3,501 Amortization of deferred lease inducements (24) --------------------------------------------------------------------- Deferred lease inducements, end of year $ 3,477 Less current portion of deferred lease inducements (292) --------------------------------------------------------------------- Non-current portion of deferred lease inducements $ 3,185 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. ASSET RETIREMENT OBLIGATIONS: The following table presents the obligation associated with the retirement of oil sands and natural gas properties: --------------------------------------------------------------------- As at December 31 2010 2009 --------------------------------------------------------------------- Asset retirement obligation, beginning of year $ 14,297 $ 12,907 Liabilities incurred 1,746 570 Liabilities settled (299) (75) Accretion 1,049 895 --------------------------------------------------------------------- Asset retirement obligation, end of year $ 16,793 $ 14,297 --------------------------------------------------------------------- --------------------------------------------------------------------- The estimated future undiscounted asset retirement obligation is $85.1 million (December 31, 2009 - $80.2 million), which has been discounted using an average credit-adjusted risk free rate of 6.32%. This obligation is estimated to be settled in periods up to 2057. 10. LONG-TERM DEBT: --------------------------------------------------------------------- As at December 31 2010 2009 --------------------------------------------------------------------- Senior secured term loan B (US$41.5 million; 2009-US$41.9 million) $ 41,240 $ 43,836 Senior secured term loan D (US$957.9 million; 2009-US$967.6 million) 952,775 1,012,741 Financing transaction costs (14,017) (16,297) --------------------------------------------------------------------- 979,998 1,040,280 Less current portion of senior secured term loan B (417) (439) Less current portion of senior secured term loan D (9,648) (10,154) --------------------------------------------------------------------- $ 969,933 $ 1,029,687 --------------------------------------------------------------------- --------------------------------------------------------------------- The Corporation's senior secured credit facilities are comprised of US$999.4 million in term loans and a three year US$185.0 million revolving credit facility. The US$41.5 million term loan B matures on April 3, 2013 and the US$957.9 million term loan D matures on April 3, 2016. The term loan B bears a floating interest rate based on either US prime or the London Interbank Offered Rate ("LIBOR"), at the Corporation's option, plus a credit spread of 100 or 200 basis points, respectively. The term loan D bears a floating interest rate based on either US prime or LIBOR, at the Corporation's option, plus a credit spread of 300 or 400 basis points, respectively. In addition, the term loan D bears an interest rate floor of 325 basis points based on US prime and an interest rate floor of 200 basis points based on LIBOR. As at December 31, 2010, $8.3 million of the revolving credit facility was utilized to support letters of credit. The US dollar denominated debt is translated into Canadian dollars at the period end exchange rate of $1 US = $0.9946 CDN (December 31, 2009 - $1 US = $1.0466 CDN). 11. SHARE CAPITAL: (a) Authorized: Unlimited number of common shares Unlimited number of preferred shares (b) Changes in issued common shares are as follows: ----------------------------------------------------------------- As at December 31 2010 2009 ----------------------------------------------------------------- Number of Number of shares Amount shares Amount ----------------------------------------------------------------- Balance, beginning of year 169,130,053 $3,137,696 128,123,287 $2,243,618 Stock options exercised 745,098 11,406 341,017 2,387 Shares issued for cash 20,000,000 700,000 40,665,749 975,978 Share issue costs, net of taxes of $9,174 (2009 - $3,698) (27,523) (84,287) ----------------------------------------------------------------- Balance, end of year 189,875,151 $3,821,579 169,130,053 $3,137,696 ----------------------------------------------------------------- ----------------------------------------------------------------- During the year ended December 31, 2010, a total of 745,098 options were exercised at a weighted average price of $11.90 per share. On August 6, 2010, the Corporation completed its initial public offering and issued 20,000,000 common shares to the public at a price of $35.00 per share. (c) Stock options: Effective June 9, 2010, the Corporation's board of directors approved a new option plan ("the 2010 Option Plan") as a replacement for the Corporation's existing stock option plan ("2003 Option Plan"). The 2010 Option Plan allows for the granting of options to directors, officers or employees and consultants of the Corporation. Options granted under the 2010 Option Plan are generally fully exercisable after three years and expire seven years after the grant date. Prior to June 9, 2010, the Corporation issued options to employees and directors under a previous option plan and under stand alone option agreements (collectively, the "Old Option Plan"). No additional options will be granted under the Old Option Plan. The Corporation has reserved 18,987,515 common shares (10% of the outstanding common shares, subject to certain restrictions) for issuance pursuant to the 2010 Option Plan and the restricted share unit plan ("the RSU Plan"). ----------------------------------------------------------------- As at December 31 2010 2009 ----------------------------------------------------------------- Weighted Weighted average average exercise exercise price price Options per share Options per share ----------------------------------------------------------------- Balance, beginning of year 12,609,407 $ 19.89 10,892,674 $ 18.86 Granted 1,208,170 33.48 2,206,500 24.00 Forfeited (152,633) 29.35 (148,750) 38.24 Exercised (745,098) 11.90 (341,017) 5.65 ----------------------------------------------------------------- Balance, end of year 12,919,846 $ 21.51 12,609,407 $ 19.89 ----------------------------------------------------------------- ----------------------------------------------------------------- (d) Restricted share units: Effective June 9, 2010, the Corporation's Board of Directors approved the RSU Plan. The RSU Plan allows for the granting of Restricted Share Units ("RSUs") to directors, officers or employees and consultants of the Corporation. An RSU represents the right for the holder to receive a cash payment or its equivalent in fully-paid common shares equal to the fair market value of the Corporation's common shares calculated at the date of such payment. RSUs granted under the RSU Plan generally vest annually over a three year period. The value of an RSU is determined based on the share price of the Corporation's common shares on the date of grant with the resulting expense recognized in earnings over the three year vesting term. ----------------------------------------------------------------- As at December 31 2010 ----------------------------------------------------------------- RSUs ----------------------------------------------------------------- Balance, beginning of year - Granted 407,610 Forfeited (2,665) ----------------------------------------------------------------- Balance, end of year 404,945 ----------------------------------------------------------------- ----------------------------------------------------------------- (e) Contributed surplus: ----------------------------------------------------------------- As at December 31 2010 2009 ----------------------------------------------------------------- Balance, beginning of year $ 55,841 $ 39,614 Stock based compensation - expensed 14,439 12,912 Stock based compensation - capitalized 3,723 3,775 Stock options exercised (2,539) (460) ----------------------------------------------------------------- Balance, end of year $ 71,464 $ 55,841 ----------------------------------------------------------------- ----------------------------------------------------------------- 12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT: The financial instruments recognized in the balance sheet are comprised of cash and cash equivalents, short-term investments, accounts receivable, debt service reserve, restricted cash, other assets, accounts payable and accrued liabilities, risk management liability and long-term debt. The carrying value of cash and cash equivalents, short-term investments, accounts receivable, debt service reserve, restricted cash and accounts payable and accrued liabilities approximates their fair value due to the short-term maturity of these instruments. Other assets and risk management liability are considered to be held-for- trading and are recorded at fair value. At December 31, 2010 the estimated fair value of long-term debt was $921.2 million. The fair value of long-term debt and the risk management liability were determined based on quoted prices from financial institutions. The Corporation has applied a discounted cash flow valuation in determining the fair value of other assets. To mitigate a portion of the risk of interest rate increases on long-term debt the Corporation had entered into interest rate swap contracts to fix the interest rate on US$700 million of the US$999.4 million total debt. The Corporation had the following interest rate swap contracts which expired on December 31, 2010: --------------------------------------------------------------------- Amount ($ million) Remaining term Fixed rate Floating rate --------------------------------------------------------------------- US$350 Oct 2010 - Dec 2010 5.29% LIBOR(1) US$60 Oct 2010 - Dec 2010 4.85% LIBOR(1) US$55 Oct 2010 - Dec 2010 4.83% LIBOR(1) US$235 Oct 2010 - Dec 2010 4.80% LIBOR(1) --------------------------------------------------------------------- (1) London Interbank Offered Rate The Corporation had previously applied hedge accounting to its interest rate swap contracts which was subsequently discontinued as the hedges were no longer effective. As at December 31, 2010, all amounts remaining in accumulated other comprehensive income related to these swaps have been amortized into earnings. --------------------------------------------------------------------- As at December 31 2010 2009 --------------------------------------------------------------------- Risk management liability, beginning of year $ 32,671 $ 61,683 Decrease in liability fair value recognized in earnings (32,671) (14,753) Decrease in liability fair value recognized in OCI - (14,259) --------------------------------------------------------------------- Risk management liability, end of year $ - $ 32,671 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- Three months ended Year ended December 31 December 31 --------------------------------------------------------------------- Risk management expense 2010 2009 2010 2009 --------------------------------------------------------------------- Realized loss on interest rate swaps $ 8,625 $ 4,945 $ 34,412 $ 17,180 Unrealized fair value gain on interest rate swaps (8,763) (4,266) (32,671) (14,753) Amortization of unrealized loss on interest rate swaps from AOCI 4,246 1,997 20,041 7,676 --------------------------------------------------------------------- $ 4,108 $ 2,676 $ 21,782 $ 10,103 --------------------------------------------------------------------- --------------------------------------------------------------------- 13. SUPPLEMENTARY INFORMATION: (a) Supplemental cash flow disclosures: --------------------------------------------------------------------- Three months ended Year ended December 31 December 31 --------------------------------------------------------------------- 2010 2009 2010 2009 --------------------------------------------------------------------- Changes in non-cash working capital items: Accounts receivable and other $ (75,738) $ (19,883) $ (63,302) $ (19,853) Short-term investments (160,444) - (167,406) - Inventories 12,234 8,870 (613) 2,226 Accounts payable 45,311 16,604 72,536 (1,749) --------------------------------------------------------------------- (178,637) 5,591 (158,785) (19,376) --------------------------------------------------------------------- Changes in non-cash working capital relating to: Operations $ (45,551) $ 3,121 $ (50,143) $ 2,022 Investing (133,086) 2,470 (108,642) (21,398) --------------------------------------------------------------------- (178,637) 5,591 (158,785) (19,376) --------------------------------------------------------------------- --------------------------------------------------------------------- Cash and cash equivalents(1): Cash $ 18,857 $ 107,074 Cash equivalents 1,205,589 855,944 --------------------------------------------------------------------- $1,224,446 $ 963,018 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) Excludes $167,406 of short term investments as at December 31, 2010. (b) Per share amounts: --------------------------------------------------------------------- Three months ended Year ended December 31 December 31 --------------------------------------------------------------------- 2010 2009 2010 2009 --------------------------------------------------------------------- Weighted average common shares outstanding 189,774,757 147,078,485 177,476,449 138,953,495 Dilutive effect of stock options and RSUs 6,369,708 4,234,716 5,778,675 4,557,334 --------------------------------------------------------------------- Weighted average common shares outstanding - diluted 196,144,465 151,313,201 183,255,124 143,510,829 --------------------------------------------------------------------- --------------------------------------------------------------------- 14. COMMITMENTS AND CONTINGENCIES: (a) Commitments The Corporation had the following commitments as at December 31, 2010. Operating: ------------------------------------------------------------------------- There- 2011 2012 2013 2014 2015 after ------------------------------------------------------------------------- Office lease rentals $ 4,031 $ 4,031 $ 4,031 $ 4,031 $ 4,060 $ 20,961 Diluent purchases 341,972 - - - - - Other commitments 2,647 1,630 3,255 1,562 - - ------------------------------------------------------------------------- Annual commitments $348,650 $ 5,661 $ 7,286 $ 5,593 $ 4,060 $ 20,961 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Capital: As part of normal operations, the Corporation has entered into a total of $177.4 million in capital commitments to be made in periods through 2015. (b) Contingencies The Corporation is involved in various legal claims associated with the normal course of operations. The Corporation believes that any liabilities that may arise pertaining to such matters would not have a material impact on its financial position. 15. COMPARATIVE FIGURES: Certain of the comparative figures have been reclassified to conform to the presentation adopted in the current period. >>Reserves and ResourcesThe Corporation has identified two commercial projects on its oil sands leases, Christina Lake and Surmont. The Christina Lake project consists of 80 contiguous square miles of oil sands leases. Thirty miles north of Christina Lake, MEG holds 32 square miles of oil sands leases at Surmont. Outside of Christina Lake and Surmont, MEG also holds over 700 sections of oil sands leases that the Corporation refers to as the Growth Properties. The Growth Properties are currently in the resource definition stage of development and provide significant additional development opportunities.GLJ, an independent reservoir engineering firm, was commissioned by MEG to evaluate the reserves and resources of the Corporation's oil sands leases. GLJ evaluated Christina Lake, Surmont and a portion of the Growth Properties. Collectively 412 sections of MEG's 864 sections of oil sands leases were evaluated. GLJ's Reserves and Resources Report is effective as of December 31, 2010.GLJ prepared estimates of reserves and resources in accordance with National Instrument 51-101 of the Canadian Securities Administrators entitled Standards of Disclosure for Oil and Gas Activities ("NI 51-101"), as well as the Canadian Oil and Gas Evaluation Handbook, or COGE Handbook, prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). MEG's complete annual disclosure required under NI 51-101 will be contained within MEG's annual information form to be filed on or before March 31, 2011.The information set forth below relating to the Corporation's reserves and resources constitute forward-looking information which is subject to certain risks and uncertainties. See "Forward-Looking Information" for important information regarding the Corporation's reserves and resources.According to GLJ, MEG's proved reserves (1P) are 606 million barrels of bitumen. The Corporation's proved-plus-probable (2P) reserves are 1,919 million barrels and its best estimate contingent resources (2C) are 3,716 million barrels. It is estimated that Christina Lake can support over 200,000 barrels per day of sustained production for 30 years and that Surmont can support 100,000 barrels per day of sustained production for over 20 years. These production capacities are based on the GLJ estimate of 2P reserves and 2C resources as of December 31, 2010.ReservesGLJ has prepared estimates of the various producing and non-producing reserve types: proved reserves (1P) and proved-plus-probable reserves (2P). All of the Corporation's reserves are at Christina Lake due to the advanced stage of development of the Christina Lake Project.GLJ has used a two-step process to determine and allocate reserves. First, GLJ utilized the pay thickness and well density for reserve categorization. GLJ assigned 1P reserves to portions of MEG's leases where continuous bitumen pay of greater than ten metres was identified with a minimum density of one well per 80 acres plus 3D seismic coverage. GLJ assigned 2P reserves to portions of the leases where continuous bitumen pay of greater than nine metres was identified with a minimum density of one well per 160 acres.The second step was to determine whether these reserves will be produced within 50 years and whether the necessary regulatory approvals are in place or submissions have been made. The reserves identified in this step are termed "marketable reserves" by GLJ. In order to be classified as marketable proved reserves, the necessary regulatory approvals must have been obtained and significant capital spending to develop the project must occur within three years. In order to be classified as marketable probable reserves all the necessary regulatory applications must have been submitted with no significant outstanding issues and significant capital spending to develop the project must occur within five years. The proved and probable reserves shown in the table below have been classified by GLJ as marketable proved reserves and marketable probable reserves, respectively.ResourcesIn addition to the reported reserves, Christina Lake, Surmont and the Growth Properties also have "resources", which are quantities of recoverable bitumen that have not met the reserves requirements at this time. Some of these resources are classified as contingent resources, pending further delineation drilling, development planning, project design and regulatory submissions or approvals. The contingent resources values set out below should be considered indicative in nature only, pending further project design work to confirm project economics, development timing and capital estimates.GLJ provided three estimates for the contingent resources category: "low estimate" (high certainty), "best estimate" (most likely) and "high estimate" (low certainty). GLJ identified a total of best estimate contingent resource of 3,716 million barrels for MEG which consists of 1,061 million barrels for Christina Lake, 837 million barrels for Surmont and 1,818 million barrels for the Growth Properties. The table below summarizes proved and probable reserves and contingent resources (best estimate) volumes and values based on GLJ's evaluation. << --------------------------------------------------------------------- Bitumen Reserves and Contingent Resources As at December 31 (Millions of barrels, before royalties) 2010 2009 % Change --------------------------------------------------------------------- Proved (1P) Reserves(1) 606 549 10 Probable Reserves(2) 1,313 1,143 15 ----------------------------------------------------------- Proved Plus Probable (2P) Reserves(1)(2) 1,919 1,692 13 Best Estimate of Contingent Resources (2C)(3)(4)(5) 3,716 3,724 0 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- Pre-tax 10% Present Value of Future Net Cash Flows As at December 31 ($ millions) 2010 2009 % Change --------------------------------------------------------------------- Proved (1P) Reserves(1) 5,388 4,387 23 Probable Reserves(2) 6,743 3,779 78 ----------------------------------------------------------- Proved Plus Probable (2P) Reserves(1)(2) 12,131 8,167 49 Best Estimate of Contingent Resources (2C)(3)(4)(5) 13,265 11,559 15 --------------------------------------------------------------------- --------------------------------------------------------------------- (1) "Proved Reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Proved Reserves are also referred to as "1P Reserves". (2) "Probable Reserves" are those additional reserves that are less certain to be recovered than Proved Reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Proved-plus-probable reserves are also referred to as "2P Reserves". (3) "Contingent Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. (4) There are three categories in evaluating Contingent Resources: Low Estimate, Best Estimate and High Estimate. The resource numbers presented all refer to the Best Estimate category. Best Estimate is a classification of resources described in the COGE Handbook as being considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the Best Estimate. If probabilistic methods are used, there should be a 50% probability (P50) that the quantities actually recovered will equal or exceed the Best Estimate. Best Estimate Contingent Resources are also referred to as "2C Resources". (5) These volumes are the arithmetic sums of the Best Estimate Contingent resources for Christina Lake, Surmont and Growth Properties. --------------------------------------------------------------------- GLJ Forecast Pricing (as utilized in the GLJ 2010 Report) --------------------------------------------------------------------- Light and Bitumen Medium Exchange Wellhead Inflation Forecast Crude Oil Rate Current Natural Gas Rate --------------------------------------------------------------------- WTI at Cushing Alberta Oklahoma Spot (US$/bbl) US$/Cdn$ (Cdn$/bbl) (Cdn$/mmbtu) %/year --------------------------------------------------------------------- 2011 88.00 0.980 61.03 4.02 0% 2012 89.00 0.980 61.14 4.61 2% 2013 90.00 0.980 60.36 5.16 2% 2014 92.00 0.980 62.13 5.62 2% 2015 95.17 0.980 64.51 6.07 2% 2016 97.55 0.980 66.24 6.38 2% 2017 100.26 0.980 68.23 6.60 2% 2018 102.74 0.980 70.03 6.75 2% 2019 105.45 0.980 72.02 6.90 2% 2020 107.56 0.980 73.56 7.05 2% 2021+ +2%/yr 0.980 +2%/yr +2%/yr 2% --------------------------------------------------------------------- --------------------------------------------------------------------- >>For further information: John Rogers, VP Investor Relations, MEG Energy Corp., (403) 770-5335, john.rogers@megenergy.com