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Husky Energy Reports Second Quarter and First Six Months Results For 2008

July 23, 2008

Husky Energy Inc. (TSX: HSE) reported net earnings of $1.36 billion or $1.61 per share (diluted) in the second quarter of 2008, an increase of 89 percent from $721 million or $0.85 per share (diluted) in the same quarter of 2007. Cash flow from operations in the second quarter of 2008 was $2.1 billion or $2.46 per share (diluted), a 66 percent increase compared with $1.3 billion or $1.48 per share (diluted) in the same quarter of 2007. Sales and operating revenues, net of royalties, were $7.20 billion in the second quarter of 2008, an increase of 128 percent compared with $3.16 billion in the same quarter of 2007.

“Husky achieved record results in the second quarter of 2008 in terms of earnings, cash flow and revenue in a strong commodity price environment,” said John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. “In the second quarter, our U.S. refining facilities also contributed to our strong results. In addition, excellent progress was made in the development of our major growth projects and we continued to strengthen our financial position.”

In the second quarter of 2008, total production averaged 359,100 barrels of oil equivalent per day, compared with 379,100 barrels of oil equivalent per day in the second quarter of 2007, a reduction of 5 percent. Total crude oil and natural gas liquids production was 256,100 barrels per day, compared with 276,500 barrels per day in 2007. The decrease in crude oil production was mainly due to the suspension of operations at White Rose for 11 days due to severe ice pack and iceberg conditions and the advancement of a scheduled 14 day turnaround at Terra Nova. Natural gas production was 618 million cubic feet per day, compared with 616 million cubic feet per day in the same period of 2007.

For the first six months of 2008, Husky’s net earnings were $2.3 billion or $2.65 per share (diluted), compared with $1.4 billion or $1.61 per share (diluted) in the first six months of 2007. Cash flow from operations was $3.6 billion or $4.28 per share (diluted) in the first six months of 2008, compared with $2.6 billion or $3.04 per share (diluted) in the same period of 2007. Sales and operating revenues, net of royalties, were $12.3 billion in the first six months of 2008, compared with $6.4 billion in the first six months of 2007.

Production for the first six months of 2008 was 354,700 barrels of oil equivalent per day, compared with 384,600 barrels of oil equivalent per day in the same period in 2007. Crude oil and natural gas liquids production was 253,900 barrels per day, compared with 279,900 barrels per day in the first six months of 2007 reflecting the advancement of scheduled turnarounds at Terra Nova and White Rose originally planned later in 2008 and the severe ice pack and iceberg conditions off the East Coast of Canada. Natural gas production was 604 million cubic feet per day, compared with 628 million cubic feet per day during the same period of 2007 as a result of a strategic decision in 2007 to reduce natural gas drilling due to weak gas prices.

Work on area infrastructure and site preparation, including roads and well pads, progressed on schedule for the Sunrise Oil Sands Project. Phase one of the Sunrise Project for 60,000 barrels per day of bitumen is expected to be operational in late 2012, subject to corporate sanction.

Planning for the development of the McMullen property located in the west central region of the Athabasca oil sands of northern Alberta progressed. Husky plans to develop production through a multi-well drilling program in 2008 using cold production technology.

The White Rose – North Amethyst satellite development off Canada’s East Coast remains on schedule for a late 2009 or early 2010 start up. The West White Rose satellite development is planned for production in 2011.

Offshore China, Husky increased its holdings by signing a petroleum contract for a new exploration block, Block 63/05. Husky also completed the acquisition of 3-D seismic data on Blocks 29/26, 29/06 and 35/18 in the second quarter. The drilling rig Seadrill West Hercules is currently undergoing commissioning in South Korea. Husky plans to commence delineation drilling on the Liwan 3-1 discovery in the third quarter of 2008.

In Indonesia, Husky completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. The agreement covers the development and further exploration of the Madura Strait Production Sharing Contract (“PSC”). The Madura BD field development plan was approved and the PSC extension has been submitted to the regulatory authorities for approval.

In the downstream business, Husky completed the conceptual stage of the reconfiguration for the Lima refinery to process heavier feedstocks. With the completion of the BP/Husky joint venture, Husky is working with BP on the reconfiguration of the Toledo refinery to process bitumen feedstock.

Following the completion of the turnarounds at White Rose and Terra Nova in the first half of 2008, crude oil production is expected to increase from current levels in the second half of the year. However, the severe ice conditions which suspended production at White Rose during the first half of the year and the ramp-up of production at the Tucker Oil Sands project will impact our annual production. Production for 2008 is now expected to be five to seven percent below our guidance range.

Husky continues to strengthen its financial position and balance sheet. Total long-term debt including current portion at June 30, 2008 was $2,129 million compared with $2,814 million at December 31, 2007. Debt to capital employed improved to 14 percent at June 30, 2008 from 19 percent at December 31, 2007. Debt to cash flow from operations decreased to 0.3 times at June 30, 2008 compared with 0.5 times at December 31, 2007.

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”) JULY 23, 2008

 ----------------------------------------------------------------------- ----- Table of Contents 1. Summary of Quarterly Financial     7. Risk Management    Results 2. Capability to Deliver Results      8. Critical Accounting Estimates    and the Strategic Plan 3. Key Growth Highlights              9. Changes in Accounting Policies 4. Business Environment               10. Outstanding Share Data 5. Results of Operations              11. Reader Advisories 6. Liquidity and Capital Resources    12. Forward-Looking Statements and                                           Information ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

1. Summary of Quarterly Financial Results

The following table shows our net earnings by industry sector and includes corporate expenses and intersegment profit eliminations.

 ----------------------------------------------------------------------- -----                                        Three months ended                        June 30 March 31  Dec. 31 Sept. 30  June 30 March 31 (millions of dollars,  except per share  amounts and ratios)      2008     2008     2007     2007     2007     2007 ---------------------------------------------------------------------------- Sales and operating  revenues, net of  royalties             $ 7,199  $ 5,086  $ 4,760  $ 4,351  $ 3,163  $ 3,244 Net earnings by sector  Upstream              $ 1,239  $   717  $   864  $   516  $   636  $   580  Midstream                 153      144      218      129       77      111  Downstream                194       38      103      121       53       20  Corporate and   eliminations            (223)     (12)    (111)       3      (45)     (61) ---------------------------------------------------------------------------- Net earnings           $ 1,363  $   887  $ 1,074  $   769  $   721  $   650 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------  Per share - Basic and   diluted              $  1.61  $  1.04  $  1.26  $  0.91  $  0.85  $  0.77 Cash flow from  operations              2,090    1,541    1,425    1,420    1,257    1,324  Per share - Basic and   diluted                 2.46     1.82     1.68     1.67     1.48     1.56 Ordinary quarterly  dividend per common  share                    0.40     0.33     0.33     0.25     0.25     0.25 Special dividend per  common share                -        -        -        -        -     0.25 Total assets            25,296   24,391   21,697   20,718   17,969   17,781 Total long-term debt  including current  portion                 2,129    3,019    2,814    2,835    1,423    1,527 Return on equity (1)  (percent)                34.9     31.2     30.2     26.6     27.1     32.1 Return on average  capital employed (1)  (percent)                30.9     26.5     25.7     22.3     23.8     27.3 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------                                                      Three months ended                                                   Dec. 31          Sept. 30 (millions of dollars, except per share amounts  and ratios)                                         2006              2006 ---------------------------------------------------------------------------- Sales and operating revenues, net of royalties    $ 3,084           $ 3,436 Net earnings by sector  Upstream                                         $   453           $   608  Midstream                                            105                87  Downstream                                            10                28  Corporate and eliminations                           (26)              (41) ----------------------------------------------------------------------------Net earnings                                      $   542           $   682 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------  Per share - Basic and diluted                    $  0.64           $  0.80 Cash flow from operations                           1,207             1,224  Per share - Basic and diluted                       1.42              1.44 Ordinary quarterly dividend per common share         0.25              0.25 Special dividend per common share                       -                 - Total assets                                       17,933            17,324 Total long-term debt including current portion      1,611             1,722 Return on equity (1) (percent)                       31.8              34.2 Return on average capital employed (1) (percent)     27.0              28.7 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Calculated for the 12 months ended for the dates shown. 

Analysis of Consolidated Earnings

Second Quarter

Sales and operating revenues in the second quarter of 2008 were more than double the same period in 2007 due to increased commodity prices, the addition of the Lima and Toledo refineries and the Minnedosa ethanol plant. During the second quarter of 2008, sales prices realized by Husky averaged U.S. $106/bbl (light, medium and heavy crude combined) compared with $57/bbl average for the second quarter of 2007. Realized natural gas prices averaged $9.14/mcf for the second quarter compared with $6.91/mcf during the same period in 2007. Commodity price increases in the upstream sector more than offset lower production.

Production in the second quarter averaged 359,100 boe per day compared with 379,100 boe per day in the same period in 2007. Production levels were lower in the second quarter due to the acceleration, from the third quarter, of the 2008 scheduled 14 day maintenance shut down at Terra Nova. Severe ice pack and iceberg conditions off the East Coast continued to be a factor in the second quarter, suspending production for 11 days and increasing operating costs at White Rose.

Operating revenues earned in the midstream sector increased significantly as a result of increased commodity prices. This was offset by corresponding increases in operating costs, largely made up of the cost of acquiring product for resale.

Downstream operating revenues and net earnings in 2008 include U.S. refining and marketing results from the Lima and Toledo refineries. The Lima refinery was acquired effective July 1, 2007 and 50% of the Toledo refinery was acquired on March 31, 2008 with an effective date of January 1, 2008. Earnings from Toledo during the period January 1, 2008 to March 31, 2008 have been included as an adjustment to the acquisition cost. In Canada, the addition of the Minnedosa ethanol plant contributed to increased operating revenues, operating costs and net earnings. The addition of these assets is the primary driver behind the increase in downstream revenue, operating costs and net earnings compared with the second quarter of 2007.

Six Months

Operating revenues increased 92% to $12.3 billion in the first six months of 2008 compared with the same period in 2007. Net earnings in the first six months of 2008 increased 64% to $2.3 billion compared with the same period in 2007. The primary drivers are the same as those discussed above impacting the second quarter.

Prices realized by Husky in the first half of 2008 were $93/bbl for light, medium and heavy oil combined and $55/bbl during the same period in 2007. Natural gas prices in 2008 averaged $8.11/mcf compared with $6.92/mcf during the same period in 2007.

Production during the six month period averaged 354,700 boe per day compared with 384,600 boe per day in the same period in 2007. In addition to the factors described above, production in the first quarter in Western Canada was impacted by extreme cold weather conditions, resulting in lower natural gas production and on the East Coast, the White Rose 2008 scheduled maintenance shut down was accelerated from August. The maintenance was moved forward in order to take advantage of an unplanned production shut down in the first quarter, which was due to operational issues.

Primary drivers in midstream and downstream operating revenue and net earnings for the first six months are the same as those impacting the second quarter.

2. Capability to Deliver Results and the Strategic Plan

Our current capacity to deliver results and the strategic plan are described in our annual MD&A and also in our Annual Information Form that are available from www.sedar.com and www.sec.gov.

In summary, our strategy is to continue to exploit our oil and gas asset base in Western Canada while expanding into new areas with large scale sustainable growth potential. Our plans include projects in Canada (the Alberta oil sands, the basins off the East Coast of Canada and the Central Mackenzie River Valley), Asia (the South China Sea, the Madura Strait and the East Java Sea) and offshore Greenland. In the midstream and downstream sectors we are enhancing performance and capturing new value throughout the value chain by further integrating our businesses, optimizing our plant operations and expanding plant and infrastructure.

3. Key Growth Highlights

To achieve corporate strategic objectives and enhance shareholder value and return on investment, we continue to develop opportunities that will drive future growth. Key highlights for the second quarter of 2008, are noted below:

Upstream

Western Canada

Husky obtained approval for its Alkaline Surfactant Polymer (“ASP”) project at Gull Lake in southwest Saskatchewan (Husky’s share 73.6%). Start up of the project is planned for the second quarter of 2009. This project is designed to increase production and improve the recovery of original oil in place by 15%.

In Lloydminster, Husky commenced commissioning on an additional heavy oil cold enhanced recovery pilot project. This project is designed to test injection of CO2 into the reservoir as a further enhancement to the recovery process. The first cold enhanced recovery pilot project continues to demonstrate positive results.

Drilling at the Trident coal bed methane development (Husky’s share 50%) is expected to increase in the second half of the year following an agreement with our partner on cost sharing. Between 100 and 120 new wells are planned for the remainder of 2008.

White Rose Development and Delineation

The North Amethyst tie-back development plan was approved by the federal and provincial governments in April 2008. Procurement of long lead equipment for the North Amethyst field is proceeding on schedule. Additional delineation and reservoir analysis at the West White Rose tie-back project will take place in the second half of 2008 and the development application is progressing as planned. The front-end engineering design for West White Rose is planned to run concurrently with the North Amethyst project execution. The South White Rose extension, the smaller of the satellite tie-back developments, was approved by the federal and provincial governments in September 2007 and is expected to augment production following completion of the North Amethyst and West White Rose tie-back projects.

The semi-submersible drilling rig, Henry Goodrich, is expected to arrive in Newfoundland and Labrador waters in August 2008. The Henry Goodrich will be available for Husky operated wells for 17 months of a total 27-month drilling program. The GSF Grand Banks semi-submersible drilling rig, which has been working at White Rose, has also been contracted for an additional period ending in January 2011. These rigs will drill several development wells in the White Rose and satellite fields, the Terra Nova field as well as exploration prospects in the Jeanne d’Arc Basin.

East Coast Exploration

Husky, together with its partners, commenced a 3-D seismic program covering 2,500 square kilometres over the White Rose and satellite fields, the Terra Nova field and on portions of five exploration licences in the Jeanne d’Arc Basin. This activity is expected to be concluded in the third quarter of 2008 and is expected to identify additional drilling opportunities.

We will participate in the drilling of an exploration well on Exploration Licence (“EL”) 1049 in the Flemish Pass Basin off the east coast of Newfoundland and Labrador. Drilling is expected to commence in the fourth quarter of 2008. StatoilHydro is the operator and Husky has a 35% interest in the licence.

Tucker Oil Sands Project

Optimization strategies to resolve start up issues and enhance the ramp-up of production are continuing. Modifications of three wells on Pad A, designed to improve the effectiveness of steam heating of the reservoir, are close to commissioning. Pad C has been expanded with eight new well pairs and steam injection has commenced on six of the eight well pairs. Drilling on the new Pad D is planned for early 2009 and will utilize experience gained from work currently underway on Pads A and C.

Sunrise Oil Sands Project

The development of the Sunrise oil sands project will proceed in multiple phases. The first development phase will produce 60 mbbls/day of bitumen commencing late 2012 and the second and third phases are targeted to increase the Sunrise production capacity to approximately 200 mbbls/day of bitumen by 2015 to 2020, subject to corporate sanction. Work on area infrastructure and site preparation, including roads and pads, progressed on schedule during the second quarter. In addition, detailed design of the facilities commenced and preparation for long lead equipment procurement and construction contracts was initiated. McMullen Development

Planning for the development of the McMullen property located in the west central region of the Athabasca oil sands of northern Alberta is progressing. Husky plans to develop production through a multi-well drilling program in 2008 using cold production technology similar to that used in the Lloydminster heavy oil operations. Husky also progressed plans to implement a pilot project that will test thermal recovery techniques.

Caribou

The preliminary engineering design of the 10 mbbls/day demonstration project commenced in the second quarter of 2008.

Saleski

Seismic analysis and reservoir studies are proceeding in preparation for the 2009 drilling program.

Offshore China Exploration

On June 25, 2008, Husky announced the acquisition of exploration Block 63/05 covering 1,777 square kilometres located in the natural gas prone Qiondongnan Basin approximately 100 kilometres south of Hainan Island. CNOOC Ltd. has the right to participate in the development of any discoveries up to a 51% working interest. Under the terms of the petroleum contract, we have committed to drill one well and acquire 300 square kilometres of seismic data within a three-year period.

The West Hercules deep water drilling rig is undergoing commissioning and is expected to arrive in the South China Sea in August 2008. The rig will initially drill the second of our planned exploration wells on Block 39/05 which surrounds the Wenchang oil field. Upon completion of this well, the first of four delineation wells is expected to spud in September 2008 at the Liwan natural gas discovery on Block 29/26.

In the second quarter of 2008, we completed a 3-D seismic data program on Blocks 29/26 and 29/06, which surround the Liwan natural gas discovery. Acquisition of 3-D seismic data was also completed on Blocks 35/18 and 50/14, which are located to the west of Hainan Island in the Yinggehai Basin. We are working toward securing a drilling rig for a multi-well program on these two blocks in 2009. The first phase exploration work commitment for these two Yinggehai blocks expires on September 30, 2009.

During the second quarter of 2008, the Wushi 23-2-1 exploration well was abandoned without testing. This well was on Block 23/15 in the Beibu Wan Basin north of Hainan Island in the South China Sea.

Indonesia Exploration and Development

In April 2008, we completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. Under the agreement, CNOOC Ltd. acquired a 50% equity interest and operatorship of Husky Oil (Madura) Limited, which holds a 100% interest in the Madura Strait Production Sharing Contract (“PSC”). The agreement covers the development and further exploration of the Madura Strait PSC. The Madura BD field development plan has been approved by the regulatory authorities and the PSC extension has been submitted for approval. Regulatory authorities are currently reviewing the work plan for the East Bawean II exploration block. Final 3-D seismic data has been delivered and preparatory work for two exploration wells is underway for the 2009 drilling program.

Offshore Greenland

The seismic acquisition vessel, Wavefield Akademic Shatsky, arrived in Nuuk, Greenland in early July, 2008 to perform a 7,000 kilometre 2-D seismic data program on Blocks 5 and 7. Husky is the operator and holds an 87.5% interest in these two blocks. The acquisition of 3,000 kilometres of 2-D seismic is planned for Block 6 later in 2008. We hold a 43.75% interest in this block. A hi-resolution aero-gravity and magnetic survey covering Husky’s blocks is approximately 40% complete.

Downstream

Lima, Ohio Refinery

An engineering evaluation has been completed to determine the reconfiguration of the Lima refinery to increase its capacity to process heavier, less costly, crude oil feedstocks; realize complex refining processing margins; and increase flexibility in product outputs. The current configuration at the Lima refinery restricts it to a predominantly light sweet crude oil feedstock. This limits our ability to process a lower cost heavier crude feedstock to meet seasonal and longer term market demands. The results are being evaluated to determine the best approach to achieve the reconfiguration.

BP/Husky Toledo, Ohio Refinery

The acquisition of 50% of the BP/Husky Toledo refinery, which has the capacity to process 150 mbbls/day of crude oil including 60 mbbls/day of blended heavy sour crude oil, closed on March 31, 2008 with an effective date of January 1, 2008. BP and Husky are planning to convert this refinery to process bitumen feedstock in conjunction with their investment in the Sunrise oil sands project.

 4. Business Environment ---------------------------------------------------------------------------- Average Benchmarks                                                          Three months ended                                                            June 30 March 31                                                               2008     2008 ---------------------------------------------------------------------------- WTI crude oil (1)            (U.S. $/bbl)                   123.98    97.90 Brent crude oil (2)          (U.S. $/bbl)                   121.38    96.90 Canadian light crude 0.3% sulphur ($/bbl)                   126.73    98.20 Lloyd heavy crude oil @ Lloydminster                                   ($/bbl)                    89.70    64.23 NYMEX natural gas (1)      (U.S. $/mmbtu)                    10.93     8.03 NIT natural gas                    ($/GJ)                     8.86     6.76 WTI/Lloyd crude blend differential                              (U.S. $/bbl)                    21.95    21.81 New York Harbor 3:2:1 crack spread                              (U.S. $/bbl)                    14.50    10.09 U.S./Canadian dollar exchange rate                                  (U.S. $)                    0.990    0.996 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Average Benchmarks                                                          Three months ended                                           Dec. 31 Sept. 30 June 30 March 31                                              2007     2007    2007     2007 ---------------------------------------------------------------------------- WTI crude oil (1)            (U.S. $/bbl)   90.68    75.38   65.03    58.16 Brent crude oil (2)          (U.S. $/bbl)   88.70    74.87   68.76    57.75 Canadian light crude 0.3% sulphur ($/bbl)   87.19    80.70   72.61    67.76 Lloyd heavy crude oil @ Lloydminster                                   ($/bbl)   42.03    43.61   39.02    38.25 NYMEX natural gas (1)      (U.S. $/mmbtu)    6.97     6.16    7.55     6.77 NIT natural gas                    ($/GJ)    5.69     5.31    6.99     7.07 WTI/Lloyd crude blend differential                              (U.S. $/bbl)   34.06    23.50   20.36    17.32 New York Harbor 3:2:1 crack spread                              (U.S. $/bbl)    8.23    11.91   24.18    12.32 U.S./Canadian dollar exchange rate                                  (U.S. $)   1.018    0.957   0.911    0.854 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Prices quoted are near-month contract prices for settlement during the     next month. (2) Dated Brent prices which are dated less than 15 days prior to loading     for delivery. 

Commodity Prices

As an integrated producer, profitability is largely determined by realized prices for crude oil and natural gas and refinery processing margins, including the effect of changes in the U.S./Canadian dollar exchange rate. All of our crude oil production and the majority of our natural gas production receive the prevailing market price. The price for crude oil is determined mainly by global factors and is beyond our control. The price for natural gas is determined primarily by the North America fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. Weather conditions also have a dramatic effect on short-term supply and demand.

During 2007, the price of WTI averaged U.S. $72/bbl and ended the year at U.S. $96/bbl. In the first quarter of 2008, the price of WTI averaged U.S. $ 98/bbl and ended the quarter at U.S. $102/bbl. During the second quarter of 2008, WTI averaged U.S. $124/bbl and ended the quarter at U.S. $140/bbl.

The steady rise in global crude oil prices over the last 18 months reflects a number of complex issues that are maintaining strong demand and uncertain supply. Chief among those issues are the emergence of new growing economies and their increasing demand for petroleum products, production uncertainties caused by geopolitical tension and uncertainties in respect of surplus productive capacity. The economic downturn in the United States during the first six months of 2008 has only marginally reduced consumption of petroleum in spite of record high fuel prices.

Natural gas prices quoted on the NYMEX rose sharply through the first six months of 2008 and were, on average, 37% higher than the same period in 2007. Higher prices in the first half of 2008 are largely attributed to comparatively colder weather, supply concerns related to facility outages in the Gulf of Mexico, comparatively lower LNG imports and working gas in storage that was lower than five-year averages. At the end of the second quarter of 2008, natural gas inventory in underground storage in the United States was 16% lower than at the same date in 2007 and the NYMEX near month price ended the second quarter of 2008 at U.S. $13.30/mmbtu. Refinery Crack Spreads

The 3:2:1 crack spread is the key indicator for refining margins since, on average, refinery gasoline output is approximately twice the distillate output. This crack spread is equal to the price of two-thirds of a barrel of gasoline plus one-third of a barrel of diesel (distillate) less one barrel of crude oil. Prices are based on NYMEX near month contract averages.

During the second quarter of 2008, the U.S. New York Harbor crack spread improved compared with the first quarter of 2008 as global markets for distillate tightened and U.S. refiners shifted their yield to favour distillate production.

Sensitivity Analysis

The following table indicates the relative annual effect of changes in certain key variables on our pre-tax cash flow and net earnings. The analysis is based on business conditions and production volumes during the second quarter of 2008. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.

 ----------------------------------------------------------------------- ----- Sensitivity Analysis                  2008 Second                                           Quarter                                           Average          Increase ---------------------------------------------------------------------------- Upstream and Midstream   WTI benchmark crude oil price        $   123.98          U.S. $1.00/bbl   NYMEX benchmark natural gas    price (1)                           $    10.93          U.S. $0.20/mmbtu   WTI/Lloyd crude blend    differential (2)                    $    21.95          U.S. $1.00/bbl Downstream   Light oil margins                    $     0.06          Cdn $0.005/litre   Asphalt margins                      $    10.80          Cdn $1.00/bbl   New York Harbor 3:2:1    crack spread (3)                    $    14.50          U.S. $1.00/bbl Consolidated   Exchange rate (U.S. $ per Cdn $) (4) $    0.990          U.S. $0.01   Interest rate                                            100 basis points   Period end translation    of U.S. $ debt (U.S. $ per Cdn $)   $ 0.982 (5)         U.S. $0.01 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Sensitivity Analysis                         Effect on Annual Pre-tax           Effect on Annual                                     Cash Flow (6)           Net Earnings (6) ----------------------------------------------------------------------------                         ($ millions) ($/share)(7)  ($ millions) ($/share)(7) Upstream and Midstream  WTI benchmark crude   oil price                      73         0.09            52         0.06  NYMEX benchmark   natural   gas price (1)                  25         0.03            18         0.02  WTI/Lloyd crude blend   differential (2)              (17)       (0.02)          (13)       (0.01) Downstream  Light oil margins               14         0.02             9         0.01  Asphalt margins                  8         0.01             5         0.01  New York Harbor 3:2:1   crack spread (3)               71         0.08            45         0.05 Consolidated  Exchange rate (U.S. $   per Cdn $) (4)               (108)       (0.13)          (72)       (0.08)  Interest rate                  (10)       (0.01)           (7)       (0.01)  Period end translation   of U.S. $ debt   (U.S. $ per Cdn $)              -            -            13         0.02 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes decrease in net earnings related to natural gas consumption. (2) Includes impact of upstream and upgrading operations only. (3) Relates to U.S. Refining & Marketing. (4) Assumes no foreign exchange gains or losses on U.S. dollar denominated     long-term debt and other monetary items. (5) U.S./Canadian dollar exchange rate at June 30, 2008. (6) Excludes derivatives. (7) Based on 849.1 million common shares outstanding as of June 30, 2008. 5. Results of Operations 5.1 Upstream ---------------------------------------------------------------------------- Upstream Net Earnings Summary          Three months              Six months                                       ended June 30           ended June 30 (millions of dollars)            2008          2007      2008          2007 ---------------------------------------------------------------------------- Gross revenues               $  3,081      $  1,828  $  5,334      $  3,591 Royalties                         657           235     1,081           433 ---------------------------------------------------------------------------- Net revenues                    2,424         1,593     4,253         3,158 Operating and administration  expenses                         409           344       793           667 Depletion, depreciation and  amortization                     352           407       742           806 Other                             (81)          (49)      (52)          (49) Income taxes                      505           255       814           518 ---------------------------------------------------------------------------- Net earnings                 $  1,239      $    636  $  1,956      $  1,216 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Net Revenue ---------------------------------------------------------------------------- Upstream Revenue Mix                   Three months              Six months                                       ended June 30           ended June 30 Percentage of upstream  net revenues                    2008          2007      2008          2007 ---------------------------------------------------------------------------- Crude oil & NGL  Light crude oil & NGL             40            53        42            52  Medium crude oil                   8             6         8             6  Heavy crude oil & bitumen         31            20        30            20 ---------------------------------------------------------------------------- Total crude oil & NGL              79            79        80            78 Natural gas                        21            21        20            22 ----------------------------------------------------------------------------                                   100           100       100           100 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Pricing ---------------------------------------------------------------------------- Average Sales Prices Realized          Three months              Six months                                       ended June 30           ended June 30                                  2008          2007      2008          2007 ---------------------------------------------------------------------------- Crude Oil           ($/bbl)  Light crude oil   & NGL                     $  121.71      $  72.28  $ 108.64      $  68.28  Medium crude oil              101.87         48.15     88.13         47.26  Heavy crude oil &   bitumen                       89.35         38.19     76.69         37.91  Total average                 106.29         56.99     93.26         54.68 Natural Gas         ($/mcf)  Average                         9.14          6.91      8.11          6.92 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

Second Quarter

During the second quarter of 2008, upstream net revenues increased by $831 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower crude oil sales volumes and higher royalties.

During the second quarter of 2008, our realized heavy crude oil prices averaged 72% of our realized light crude oil prices versus 52% during the same period in 2007.

Six Months

For the six months ended June 30, 2008, upstream net revenues increased by $1,095 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower crude oil and natural gas sales volumes and higher royalties.

During the first six months of 2008, our realized heavy crude oil prices averaged 69% of our realized light crude oil prices versus 55% during the same period in 2007.

 Oil and Gas Production ---------------------------------------------------------------------------- Daily Gross Production                     Three months          Six months                                           ended June 30       ended June 30                                          2008      2007      2008      2007 ---------------------------------------------------------------------------- Crude oil & NGL             (mbbls/day)  Western Canada   Light crude oil & NGL                  24.0      25.3      24.7      27.6   Medium crude oil                       27.0      26.8      27.0      27.2   Heavy crude oil & bitumen             105.5     105.4     104.9     106.7 ----------------------------------------------------------------------------                                         156.5     157.5     156.6     161.5  East Coast Canada   White Rose - light    crude oil                             75.6      90.3      71.6      89.9   Terra Nova - light   crude oil                             12.5      15.5      13.7      15.0  China   Wenchang - light crude    oil & NGL                             11.5      13.2      12.1      13.5 ---------------------------------------------------------------------------- Total crude oil & NGL                   256.1     276.5     254.0     279.9 ---------------------------------------------------------------------------- Natural gas                  (mmcf/day) 618.0     615.7     604.2     627.8 ---------------------------------------------------------------------------- Total                        (mboe/day) 359.1     379.1     354.7     384.6 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

Crude Oil and NGL Production

Second Quarter

In the second quarter of 2008, crude oil and NGL production decreased by 7% compared with the same period in 2007. Production from the White Rose field was shut down for 11 days in April as a result of ice encroachment due to severe ice pack and iceberg conditions. Production from White Rose averaged 76 mbbls/day during the second quarter of 2008 compared with 90 mbbls/day during the same period in 2007.

In June 2008, Terra Nova was shut down for 14 days for a scheduled maintenance turnaround that was originally planned to take place in July.

Six Months

In the first half of 2008, crude oil and NGL production decreased by 9% compared with the same period of the previous year. In addition to the issues impacting the second quarter, White Rose production was reduced by a 13-day turnaround for scheduled maintenance of the SeaRose FPSO during the first quarter of 2008. This maintenance turnaround was originally scheduled for August.

During the first half of 2008, crude oil and NGL production from Western Canada was down 3% compared with the first half of 2007, primarily due to the disposition of non-core oil properties.

Natural Gas Production

Second Quarter

Production of natural gas was marginally higher in the second quarter of 2008 compared with the same period in 2007. During the second quarter of 2008, new natural gas wells tied-in offset normal reservoir declines and reduced production resulting from turnarounds.

In the second quarter of 2008, 60% of our natural gas production was from the foothills of Alberta and British Columbia, the deep basin of Alberta and the plains of northeast British Columbia and northwest Alberta; the remainder was from the plains throughout Alberta and southwest Saskatchewan.

Six Months

During the first half of 2008, natural gas production was 4% lower than the year before due to severe cold weather in Western Canada in the first quarter and reduced drilling activity in 2007 in response to low natural gas prices and pending higher Alberta gas royalties. This was offset by higher second quarter production as discussed above.

 Production Guidance ---------------------------------------------------------------------------- 2008 Gross Production Guidance                      Six months   Year ended                                        Guidance  ended June 30      Dec. 31                                            2008           2008         2007 ---------------------------------------------------------------------------- Crude oil & NGL           (mbbls/day)  Light crude oil & NGL                139 - 148            122          139  Medium crude oil                       28 - 29             27           27  Heavy crude oil & bitumen            114 - 124            105          107 ----------------------------------------------------------------------------                                       281 - 301            254          273 Natural gas                (mmcf/day) 625 - 655            604          623 Total barrels of oil  equivalent                (mboe/day) 385 - 410            355          377 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

Following the completion of the turnarounds at White Rose and Terra Nova in the first half of 2008, crude oil production is expected to increase from current levels in the second half of the year. However, the severe ice conditions which suspended production at White Rose during the first half of the year and the ramp-up of production at the Tucker Oil Sands project will impact our annual production. Production for 2008 is now expected to be five to seven percent below our guidance range.

Royalties

In the second quarter of 2008, royalty rates in Western Canada averaged 16% as a percentage of gross revenue, unchanged from the second quarter of 2007.

In March 2008, the Tier II incremental royalty rate became effective for White Rose. East coast offshore royalty rates averaged 31% as a percentage of gross revenue in the second quarter compared with 8% in the second quarter of 2007.

Royalty rates for the first six months of 2008 averaged 16% in Western Canada and 28% offshore east coast compared with 16% and 6% in 2007.

Unit Operating Costs

Second Quarter

In the second quarter of 2008, operating costs in Western Canada averaged $12.95/boe compared with $11.10/boe in the same period in 2007. Increasing operating costs in Western Canada are generally related to the nature of exploitation necessary to manage production from maturing fields and new more extensive but less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, facilities associated with enhanced recovery schemes, more extensive pipeline systems, crude and water trucking and more extensive natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. In addition, higher levels of industry activity lead naturally to competition for resources and consequential higher service rates and unit costs. Our efforts are focused on managing rising operating costs with initiatives such as the establishment of a logistics support division to control costs of transporting production. We strive to keep our infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure fully utilized.

Operating costs at the East Coast offshore operations averaged $5.47/bbl in the second quarter of 2008 compared with $4.00/bbl in the second quarter of 2007. The higher unit operating cost in 2008 was due to lower production volume. Operating costs in total were $5 million higher in the second quarter of 2008 compared with 2007 due to additional resources required to manage ice encroachment and subsurface mechanical issues. Operating costs at the South China Sea offshore operations averaged $5.19/bbl in the second quarter of 2008 compared with $3.04/bbl in the same period in 2007 as a result of higher maintenance costs.

Six Months

Total upstream operating costs in the first half of 2008 increased by 17% over 2007. In addition to the factors affecting the second quarter, operating costs were adversely affected in the first quarter by extreme cold weather in Western Canada, which resulted in increased costs for gas well servicing and methanol injection to deal with gas well freeze ups and the scheduled turnaround of the Sea Rose FPSO.

Unit Depletion, Depreciation and Amortization

Second Quarter

Total unit DD&A averaged $10.78/boe in the second quarter of 2008 compared with $11.79/boe in the second quarter of 2007. In Canada, unit DD&A was $10.81/boe, a decrease of 8% over the second quarter of 2007. The lower DD&A rate in Canada was primarily due to the disposition of 50% of the Sunrise oil sands asset, which reduced the full cost base by approximately $1.8 billion or $1.90/boe in the second quarter of 2008. The Sunrise oil sands project currently does not have any proved reserves attributed to it.

Six Months

For the first six months of 2008 total unit DD&A averaged $11.50/boe compared with $11.58/boe during the same period in 2007 primarily due to the effect of the Sunrise disposition largely offset by a higher full cost base in the first quarter of 2008 compared with the first half of 2007.

 ----------------------------------------------------------------------- ----- Netback Analysis                           Three months          Six months                                           ended June 30       ended June 30                                          2008      2007      2008      2007 ----------------------------------------------------------------------------                                             $         $         $         $ Total  Crude oil equivalent (per boe) (1)   Gross price                           91.53     52.56     80.60     51.10   Royalties                             19.77      6.81     16.52      6.21 ----------------------------------------------------------------------------   Net sales price                       71.76     45.75     64.08     44.89   Operating costs (2)                   10.91      8.84     10.83      8.59 ----------------------------------------------------------------------------   Operating netback                     60.85     36.91     53.25     36.30   DD&A                                  10.78     11.79     11.50     11.58   Administration expenses and    other (2)                            (3.30)    (0.71)    (1.17)    (0.19) ----------------------------------------------------------------------------   Earnings before income taxes          53.37     25.83     42.92     24.91 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Western Canada  Crude oil (per boe) (1)  Light crude oil    Gross price                          99.68     59.41     88.70     58.08    Royalties                            13.61      6.32     11.88      6.26 ----------------------------------------------------------------------------    Net sales price                      86.07     53.09     76.82     51.82    Operating costs (2)                  14.17     13.89     15.29     12.82 ----------------------------------------------------------------------------    Operating netback                    71.90     39.20     61.53     39.00 ----------------------------------------------------------------------------   Medium crude oil    Gross price                          99.28     47.81     85.87     46.99    Royalties                            17.71      8.38     15.48      8.17 ----------------------------------------------------------------------------    Net sales price                      81.57     39.43     70.39     38.82    Operating costs (2)                  16.23     12.48     15.36     13.03 ----------------------------------------------------------------------------    Operating netback                    65.34     26.95     55.03     25.79 ----------------------------------------------------------------------------   Heavy crude oil & bitumen    Gross price                          88.74     38.30     76.19     37.98    Royalties                            12.17      4.97     10.21      4.84 ----------------------------------------------------------------------------    Net sales price                      76.57     33.33     65.98     33.14    Operating costs (2)                  15.91     12.96     15.43     12.40 ----------------------------------------------------------------------------    Operating netback                    60.66     20.37     50.55     20.74 ----------------------------------------------------------------------------  Natural gas (per mcfge) (3)   Gross price                            9.52      7.04      8.51      7.03   Royalties                              1.86      1.37      1.65      1.41 ----------------------------------------------------------------------------   Net sales price                        7.66      5.67      6.86      5.62   Operating costs (2)                    1.43      1.35      1.49      1.34 ----------------------------------------------------------------------------   Operating netback                      6.23      4.32      5.37      4.28 ---------------------------------------------------------------------------- East Coast  Light crude oil (per boe) (1)   Gross price                          124.72     73.79    111.74     70.17   Royalties (4)                         38.89      6.04     31.62      4.10 ----------------------------------------------------------------------------   Net sales price                       85.83     67.75     80.12     66.07   Operating costs (2)                    5.47      4.00      5.37      3.52 ----------------------------------------------------------------------------   Operating netback                     80.36     63.75     74.75     62.55 ---------------------------------------------------------------------------- International  Light crude oil (per boe) (1)   Gross price                          131.62     75.14    115.39     71.65   Royalties                             36.99     14.43     31.55     12.36 ----------------------------------------------------------------------------   Net sales price                       94.63     60.71     83.84     59.29   Operating costs (2)                    5.19      3.04      4.90      3.98 ----------------------------------------------------------------------------   Operating netback                     89.44     57.67     78.94     55.31 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Includes associated co-products converted to boe. (2) Operating costs exclude accretion, which is included in administration     expenses and other. (3) Includes associated co-products converted to mcfge. (4) During March 2008, White Rose royalties achieved payout status for Tier     2 royalties. 

Other Items

During the second quarter of 2008, an $11 million gain was recorded on an embedded derivative related to a drilling rig contract requiring payment in U.S. currency compared with a $49 million gain in the second quarter of 2007. A loss of $17 million was recorded in the first six months of 2008 compared with a gain of $49 million for the same period in 2007. The payments are expected to occur over the three-year period from mid-2008. The amount will fluctuate with the U.S./Cdn forward exchange rate until actual contract settlement. Contracts to purchase U.S. currency have been entered into which offset approximately 60% of this derivative. (Refer to Note 16 to the Consolidated Financial Statements).

Other items also include a gain of $69 million on the sale of 50% of Husky Oil (Madura) Limited to CNOOC Ltd. in the second quarter of 2008.

Upstream Capital Expenditures

By the end of the first half of 2008, overall upstream capital expenditures were 47% of the 2008 capital expenditure guidance. Delays are related to semi-submersible drilling rig delivery dates, contracting for consulting engineering services and receiving regulatory approvals. Our major upstream projects remain on schedule and their ultimate completion dates are expected to be maintained.

 ----------------------------------------------------------------------- -----                                            Three months         Six months Capital Expenditures Summary (1)          ended June 30       ended June 30 (millions of dollars)                    2008      2007      2008      2007 ---------------------------------------------------------------------------- Exploration  Western Canada                      $    103  $     76  $    309  $    241  East Coast Canada and Frontier            20         -        45         5  International                             32        20        62        25 ----------------------------------------------------------------------------                                           155        96       416       271 ---------------------------------------------------------------------------- Development  Western Canada                           394       357       863       745  East Coast Canada                         73        62       141       116  International                              3         5         3         5 ----------------------------------------------------------------------------                                           470       424     1,007       866 ----------------------------------------------------------------------------                                      $    625  $    520  $  1,423  $  1,137 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Excludes capitalized costs related to asset retirement obligations     incurred during the period. 

During the first six months of 2008, capital expenditures were $1,172 million (82%) in Western Canada, $186 million (13%) off the East Coast of Canada and $65 million (5%) offshore China and Indonesia.

The following table discloses the number of gross and net exploration and development wells we completed in Western Canada and the oil sands during the periods indicated. All of the net exploration wells and net development wells we drilled in the second quarter of 2008 resulted in wells capable of commercial production.

 ----------------------------------------------------------------------- ----- Western Canada and Oil Sands        Three months             Six months  Wells Drilled                     ended June 30           ended June 30                                   2008       2007         2008       2007                                Gross  Net Gross  Net   Gross  Net Gross  Net ---------------------------------------------------------------------------- Exploration     Oil                5    3    13   13      28   26    33   33                 Gas                7    4     4    3      64   53    69   59                 Dry                -    -     1    1      20   19    10   10 ----------------------------------------------------------------------------                                   12    7    18   17     112   98   112  102 ---------------------------------------------------------------------------- Development     Oil               73   73    58   54     193  177   196  184                 Gas               19   17     6    4     135  104   174  141                 Dry                -    -     2    2       3    3    12   12 ----------------------------------------------------------------------------                                   92   90    66   60     331  284   382  337 ---------------------------------------------------------------------------- Total                            104   97    84   77     443  382   494  439 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- 

Western Canada – Excluding Oil Sands

During the first six months of 2008, we invested $994 million on exploration and development in Western Canada excluding oil sands, which produces variously light, medium, heavy crude oil or natural gas throughout the Western Canada Sedimentary Basin. Of this, $527 million was invested on properties in Alberta, northeast British Columbia and southern Saskatchewan primarily to further develop and extend properties with proved reserves. We drilled 382 net wells in these regions during the first six months of 2008, resulting in 203 net oil wells and 144 net natural gas wells. In the Lloydminster area of Alberta and Saskatchewan, from which the majority of our heavy crude oil is produced, we invested $388 million in this same period, to extend proved properties, implement cost reduction initiatives and perform engineering studies in respect of improved recovery schemes. Our high impact exploration program is conducted along the foothills of Alberta and British Columbia and in the deep basin region of Alberta. In the first six months of 2008, we invested $79 million drilling in these natural gas prone areas. During the first six months of 2008, we drilled 15 net exploration wells in the foothills/deep basin regions; 13 were cased as natural gas wells. The remaining 83 net exploration wells were drilled primarily in the shallow regions of the Western Canada Sedimentary Basin.

Oil Sands

Oil sands capital expenditures totaled $178 million during the first six months of 2008. At Tucker, we spent $63 million on drilling new well pairs, facility modification and new pad preparation. At Sunrise, we spent $84 million on engineering design, site preparation and facilities and equipment requisitions. At Caribou and Saleski we spent $31 million on project development.

East Coast Development

During the first half of 2008, we spent $141 million primarily for SeaRose FPSO tie-back projects and White Rose capital enhancements. Construction commenced on North Amethyst long lead equipment, engineering design began for the West White Rose development and infill drilling commenced at the White Rose South Avalon field.

East Coast and Northwest Territories Exploration

During the first half of 2008, we spent $45 million on two exploration wells in the Central Mackenzie Valley and on preliminary planning for our East Coast seismic program.

International

During the first half of 2008, we spent $62 million on exploration drilling in the South China Sea and seismic on the East Bawean II exploration block in the Java Sea.

2008 Guidance

Our 2008 Upstream Capital expenditure guidance remains unchanged from that reported in our 2007 annual MD&A.

 ----------------------------------------------------------------------- ----- 2008 Capital Expenditure Guidance (1) (millions of dollars) ---------------------------------------------------------------------------- Western Canada - oil & gas                                          $ 1,670                - oil sands                                              300 East Coast Canada                                                       650 International                                                           430 ----------------------------------------------------------------------------                                                                     $ 3,050 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Excludes capitalized administrative costs and capitalized interest. 5.2 Midstream ---------------------------------------------------------------------------- Upgrading Net Earnings Summary               Three months       Six months                                             ended June 30     ended June 30 (millions of dollars, except where  indicated)                                 2008     2007     2008     2007 ---------------------------------------------------------------------------- Gross margin                             $   168  $    89  $   339  $   227 Operating and administration expenses         67       47      130      105 Other recoveries                              (1)      (1)      (2)      (2) Depreciation and amortization                  7        4       13       10 Income taxes                                  28       10       59       34 ---------------------------------------------------------------------------- Net earnings                             $    67  $    29  $   139  $    80 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- Selected operating data:  Upgrader throughput (1)    (mbbls/day)     58.5     36.1     60.7     52.5  Synthetic crude oil sales  (mbbls/day)     51.6     32.9     53.6     45.3  Upgrading differential     ($/bbl)      $ 30.12  $ 30.41  $ 29.28  $ 26.42  Unit margin                ($/bbl)      $ 35.61  $ 29.74  $ 34.69  $ 27.64  Unit operating cost (2)    ($/bbl)      $ 12.53  $ 14.37  $ 11.73  $ 11.05 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Throughput includes diluent returned to the field. (2) Based on throughput. 

The upgrading business segment adds value by processing heavy sour crude oil into high value synthetic crude oil and low sulphur distillates. The upgrader profitability is primarily dependent on the differential between the cost of the heavy crude feedstock and the sales price of the synthetic crude oil.

Second Quarter

During the second quarter of 2008, the upgrading differential averaged $30.12/bbl, marginally lower than a year earlier. The differential is equal to Husky Synthetic Blend, which sells at a premium to West Texas Intermediate, less Lloyd Heavy Blend. During the second q