MEG Energy announces 2010 fourth quarter financial and operating results and December 31, 2010 reserve and resource estimates
03.02.2011 | CNW
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:
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Three months ended Year ended
December 31 December 31
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($000 except per share
amounts and as noted) 2010 2009 2010 2009
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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
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(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
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Non-GAAP Measurements ($000) 2010 2009 2010 2009
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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
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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)
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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
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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
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($ 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:
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Year ended
December 31 2010
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2010 2009 Q4 Q3 Q2 Q1
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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$/bbl) 51.76 45.01 51.43 51.73 48.73 58.10
Bitumen sales
(bbls/d)(1) 21,292 3,416 27,648 19,376 24,562 13,447
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2009
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Q4 Q3 Q2 Q1
--------------------------------
Commodity Prices
(Average Prices)
Crude oil prices
West Texas
Intermediate
(WTI) US$/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
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(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
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Three months ended Year ended
December 31 December 31
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Cash operating netback ($000) 2010 2009 2010 2009
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Blend sales(1) 241,020 47,089 717,610 94,295
Cost of diluent(2) (110,199) (18,932) (315,350) (38,180)
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Bitumen sales 130,821 28,157 402,260 56,115
Transportation and other
selling costs (3,197) (3,832) (12,480) (12,767)
Royalties (5,777) (1,136) (16,521) (1,705)
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Net bitumen revenue 121,847 23,189 373,259 41,643
Operating costs - energy (12,384) (10,289) (50,288) (15,183)
Operating costs - non-energy (23,786) (18,056) (111,853) (54,383)
Power sales 7,330 3,971 29,197 5,048
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Cash operating netback(3) 93,007 (1,185) 240,315 (22,875)
Less capitalized(4) - 680 - (21,010)
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Cash operating netback in
statement of operations(4) 93,007 (1,865) 240,315 (1,865)
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Three months ended Year ended
December 31 December 31
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Production and Sales Volume
Summary (bbls/d) 2010 2009 2010 2009
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Blend sales(1) 40,964 8,376 31,192 4,838
Diluents(2) (13,316) (2,456) (9,900) (1,422)
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Bitumen sales 27,648 5,920 21,292 3,416
(Increase) decrease in
inventory 96 13 (35) 51
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Total bitumen production 27,744 5,933 21,257 3,467
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Power sales (MWh) 163,198 89,434 585,476 98,914
Power realization (CDN$/MWh) 44.91 44.40 49.87 51.97
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Three months ended Year ended
December 31 December 31
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Cash operating netback
($ per barrel) 2010 2009 2010 2009
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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)
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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
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Cash Operating Netback(3) 36.56 (2.18) 30.92 (18.35)
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(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 ofbitumen.
(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
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Three months ended Year ended
December 31 December 31
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($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
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Total G&A Costs 13,689 7,259 47,661 33,871
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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)
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Three months ended Year ended
December 31 December 31
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($000) 2010 2009 2010 2009
-------------------------------------------------------------------------
Long-term debt (35,268) (18,529) (52,186) (127,258)
Debt service reserve 913 - 2,195 3,832
US$ denominated cash and
cash equivalents 457 811 1,445 4,843
Other (416) (55) (509) (1,524)
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Foreign exchange loss(gain) (34,314) (17,773) (49,055) (120,107)
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US$ - Canadian $ exchange rate
As at December 31, 2010 2009 2008
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C$ equivalent of 1 US dollar 0.9946 1.0466 1.2246
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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
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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
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Total risk management loss 4,108 2,676 21,782 10,103
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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
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Three months ended Year ended
December 31 December 31
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($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)
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Interest expense 11,128 3,425 44,785 4,519
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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
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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
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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
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$ 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
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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
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1,166,884 1,173,380
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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
-------------------------------------------------------------------------
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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
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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
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(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 - $1,919)
See accompanying notes to financial statements.
MEG ENERGY CORP.
Statement of Cash Flows
(Unaudited)
[table] -------------------------------------------------------------------------
Three months ended Year ended
December 31 December 31
-------------------------------------------------------------------------
($ 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