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

CALGARY, 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 HIGHLIGHTS

The 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 Measurements

The 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.

    <<
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                                    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)
    -------------------------------------------------------------------------
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    (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 RESULTS

The 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 OPERATIONS

Since 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 Compensation

Stock-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 Accretion

Depletion 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 Taxes

Future 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 INVESTING

The 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 Project

During 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 Properties

The 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 Acquisitions

During 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-Cash

Non-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 Information

This 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 Measures

This 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 Resources

The 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.

Reserves

GLJ 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.

Resources

In 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%
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
    >>

SOURCE MEG Energy Corp.

For further information: John Rogers, VP Investor Relations, MEG Energy Corp., (403) 770-5335, john.rogers@megenergy.com


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