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

CALGARY, ALBERTA, Jul 23 (MARKET WIRE) --
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

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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

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1. Summary of Quarterly Financial Results

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

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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
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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)
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Net earnings $ 1,363 $ 887 $ 1,074 $ 769 $ 721 $ 650
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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
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Three months ended
Dec. 31 Sept. 30
(millions of dollars, except per share amounts
and ratios) 2006 2006
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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
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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
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(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
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Average Benchmarks
Three months ended

June 30 March 31
2008 2008

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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
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Average Benchmarks
Three months ended

Dec. 31 Sept. 30 June 30 March 31
2007 2007 2007 2007

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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
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(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.

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Sensitivity Analysis 2008 Second
Quarter
Average Increase
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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. $0.01
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Sensitivity Analysis
Effect on Annual Pre-tax Effect on Annual
Cash Flow (6) Net Earnings (6)
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($ 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
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(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
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Upstream Net Earnings Summary Three months Six months
ended June 30 ended June 30

(millions of dollars) 2008 2007 2008 2007
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Gross revenues $ 3,081 $ 1,828 $ 5,334 $ 3,591
Royalties 657 235 1,081 433
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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
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Net earnings $ 1,239 $ 636 $ 1,956 $ 1,216
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Net Revenue
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Upstream Revenue Mix Three months Six months
ended June 30 ended June 30
Percentage of upstream
net revenues 2008 2007 2008 2007
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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
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Total crude oil & NGL 79 79 80 78
Natural gas 21 21 20 22
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100 100 100 100
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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 quarter of 2008,
the overall unit margin was 20% higher than a year earlier partly due to
the addition of low sulphur off-road diesel to the upgrader's product
stream.

Upgrader throughput was 62% higher in the second quarter of 2008 compared
with the same period in 2007. Throughput was low during the second
quarter of 2007 due to a 49-day scheduled turnaround and installation of
new coke drums. Throughput was below capacity during the second quarter
of 2008 due to a temporary shutdown to replace the hydrogen plant
catalyst. Unit operating costs decreased by 13% in the second quarter of
2008 compared with a year earlier as a result of higher throughput which
increased at a higher rate than increases in total operating costs.
Operating cost increases were mainly attributable to higher energy costs.

Six Months

During the first half of 2008, upgrading earnings were 74% higher than
the year earlier, primarily due to the same factors that affected the
second quarter.

----------------------------------------------------------------------------

Infrastructure and Marketing Net Three months Six months
Earnings Summary ended June 30 ended June 30

(millions of dollars, except where
indicated) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross margin - pipeline $ 44 $ 28 $ 69 $ 54
- other infrastructure
and marketing 90 48 179 120
----------------------------------------------------------------------------
134 76 248 174
Operating and administration expenses 4 - 7 4
Depreciation and amortization 7 7 15 14
Income taxes 37 21 68 48
----------------------------------------------------------------------------
Net earnings $ 86 $ 48 $ 158 $ 108
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline throughput
(mbbls/day) 539 506 521 500
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Second Quarter

Infrastructure and marketing net earnings in the second quarter of 2008
were $86 million compared with $48 million in the second quarter of 2007.
Higher earning were primarily due to higher pipeline throughput and
tariffs and higher brokering margins on crude oil and sulphur.

Six Months

During the first half of 2008, infrastructure and marketing earnings were
46% higher than the year earlier primarily because of the same factors
that affected the second quarter of 2008.

Midstream Capital Expenditures

Midstream capital expenditures totalled $65 million in the first six
months of 2008: $51 million was spent at the Lloydminster upgrader,
primarily for contingent consideration and facility reliability projects.
The remaining $14 million was spent on the pipeline extension between
Lloydminster and Hardisty, Alberta.

5.3 Downstream
----------------------------------------------------------------------------
Canadian Refined Products Net Three months Six months
Earnings Summary ended June 30 ended June 30

(millions of dollars, except where
indicated) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross margin - fuel sales $ 50 $ 63 $ 88 $ 105
- ancillary sales 14 10 24 19
- asphalt sales 28 36 47 49
----------------------------------------------------------------------------
92 109 159 173
Operating and administration expenses 22 20 26 38
Depreciation and amortization 20 15 40 31
Income taxes 15 21 28 31
----------------------------------------------------------------------------
Net earnings $ 35 $ 53 $ 65 $ 73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected
operating data:
Number of fuel
outlets 498 504
Light oil sales (million litres/day) 7.9 8.6 7.9 8.8
Light oil retail
sales per
outlet (thousand litres/day) 12.6 13.3 12.9 12.8
Prince George
refinery
throughput (mbbls/day) 10.5 8.4 11.0 9.7
Asphalt sales (mbbls/day) 23.0 19.5 20.4 18.4
Lloydminster
refinery
throughput (mbbls/day) 26.4 18.5 24.2 21.6
Ethanol
production (thousand litres/day) 600.1 305.9 624.6 313.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Canadian Refined Products

Second Quarter

During the second quarter of 2008, we benefited from higher throughput at
the Prince George refinery, which produces a high gasoline yield.
However, earnings from sales of gasoline and diesel were lower than a
year earlier due to lower sales volume and slightly lower margins. Sales
volumes were down as a result of supply shortages from our third party
refined product suppliers due to refinery outages. Ancillary income from
convenience store and restaurant sales continues to grow.

Second quarter 2008 ethanol production increased 96% due to the start-up
of the Minnedosa ethanol plant, which commenced operations at the end of
2007. This was offset by a 68% reduction in margins in 2008 due to the
run up of corn prices, reduced demand and increases in natural gas prices.

During the second quarter of 2008, asphalt product margins were
approximately 42% lower than a year earlier, partially offset by
increased sales volumes. Asphalt margins were impacted by the increase in
heavy crude oil feedstock costs. Additional value was captured in the
quarter from higher volumes of residuals and distillates produced at the
Lloydminster refinery and processed at the Lloydminster upgrader into low
sulphur off-road diesel and synthetic crude oil.

Six Months

During the first half of 2008, earnings from gasoline and diesel were
lower than the same period of 2007 as a result of the same factors
affecting the second quarter. Earnings from ethanol sales were higher
than the previous year as higher sales volume more than offset lower unit
margins. Margins on asphalt products were lower than the same period in
the previous year due to rising crude oil feedstock costs.

----------------------------------------------------------------------------

U.S. Refining and Marketing Net Three months Six months
Earnings Summary ended June 30 ended June 30

(millions of dollars, except where indicated) 2008 2008
----------------------------------------------------------------------------
Gross refining margin $ 398 $ 485
Processing costs 106 159
Operating and administration expenses 1 2
Interest - net - 1
Depreciation and amortization 43 62
Income taxes 89 94
----------------------------------------------------------------------------
Net earnings $ 159 $ 167
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Lima refinery throughput (mbbls/day) 144.1 141.2
Toledo refinery throughput (mbbls/day) 66.0 66.0 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Toledo refinery operating results are included from March 31, 2008,
the date the acquisition was completed. Throughput represents three
months of operations.

U.S. Refining and Marketing

The U.S. Refining and Marketing segment commenced operations on July 1,
2007 with the acquisition of the Lima, Ohio refinery. The Lima refinery
has a crude oil throughput capacity of 160 mbbls/stream day.

On March 31, 2008, we completed a transaction that resulted in the
formation of two joint entities forming an integrated oil sands business.
The downstream entity is a 50% interest in the BP Toledo refinery, which
has a crude distillation capacity of 150 mbbls/day. The transaction was
effective January 1, 2008 and the results of its operations for the first
quarter of 2008 were reflected as an adjustment to the value assigned to
the refinery assets transferred to the downstream entity on March 31,
2008. The second quarter of 2008 is the first period that the BP/Husky
Toledo refinery's results of operations have been reflected in our
earnings.

In the downstream sector, the drop in demand for motor fuels that began
in mid-2007 continued through the first half of 2008, in line with U.S.
economic conditions and record high fuel prices. Lower consumption
combined with higher product stocks resulted in narrow refinery crack
spreads. Crack spreads improved in the second quarter primarily on
distillates, which were in high demand globally.

Downstream Capital Expenditures

Downstream capital expenditures totalled $88 million during the first six
months of 2008. Capital spending was primarily related to various
environmental protection and reliability upgrades at our refineries and
plants and for marketing location upgrades and construction.

5.4 Corporate
----------------------------------------------------------------------------
Corporate Summary Three months Six months
ended June 30 ended June 30

(millions of dollars) income (expense) 2008 2007 2008 2007
----------------------------------------------------------------------------
Intersegment eliminations - net $ (128) $ (33) $ (137) $ (58)
Administration expenses (139) (55) (90) (93)
Depreciation and amortization (7) (7) (14) (12)
Interest - net (41) (22) (86) (43)
Foreign exchange (6) 36 (16) 37
Income taxes 98 36 108 63
----------------------------------------------------------------------------
Net earnings (loss) $ (223) $ (45) $ (235) $ (106)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Intersegment eliminations are profit included in inventory that has
not been sold to third parties at the end of the period.

In the second quarter of 2008, administration expenses included
stock-based compensation expense of $114 million compared with $43
million in the same period in 2007. The increase in net interest expense
during the second quarter of 2008 compared with a year earlier was
primarily due to a higher level of debt. Additional debt was issued
during 2007 for the acquisition of the Lima refinery.

----------------------------------------------------------------------------

Foreign Exchange Summary Three months Six months
ended June 30 ended June 30

(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized (gain) loss
on translation of U.S.
dollar denominated
long-term debt $ (10) $ (101) $ 34 $ (115)
Cross currency swaps 3 32 (11) 36
Contribution receivable 11 - 11 -
Other (gains) losses 2 33 (18) 42
----------------------------------------------------------------------------
$ 6 $ (36) $ 16 $ (37)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of period U.S. $0.973 U.S. $0.867 U.S. $1.012 U.S. $0.858
At end of period U.S. $0.982 U.S. $0.940 U.S. $0.982 U.S. $0.940
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate Capital Expenditures

Corporate capital expenditures totaled $26 million in the first six
months of 2008 primarily for office and information system upgrades.

Consolidated Income Taxes

During the second quarter of 2008, consolidated income taxes consisted of
$234 million of current taxes and $342 million of future taxes compared
with current taxes of $66 million and future taxes of $205 million in the
same period of 2007. The increase in current taxes in the second quarter
of 2008 compared with the second quarter of 2007 was due to the deferral
of White Rose income in 2007. The increase in future taxes in the second
quarter of 2008 compared with the same period in 2007 was due to an
increase in earnings.

6. Liquidity and Capital Resources

During the second quarter of 2008, cash flow from operating activities
financed all of our capital requirements, dividend payment and repayment
of debt. At June 30, 2008 we had $1.5 billion in unused committed credit
facilities.

----------------------------------------------------------------------------

Cash Flow Summary Three months Six months
ended June 30 ended June 30

(millions of dollars, except ratios) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash flow - operating activities $ 2,054 $ 1,136 $ 3,281 $ 1,808
- financing activities $(1,217) $ (454) $(1,318) $ (676)
- investing activities $ (667) $ (549) $(1,635) $ (1,441)
Financial Ratios
Debt to capital employed (percent) 13.8 12.1
Corporate reinvestment ratio
(percent) (1) (2) 78 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated for the 12 months ended for the dates shown.
(2) Reinvestment ratio is based on net capital expenditures including
corporate acquisitions.

6.1 Operating Activities

In the second quarter of 2008, cash generated from operating activities
amounted to $2.1 billion compared with $1.1 billion in the second quarter
of 2007. Higher cash flow from operating activities was primarily due to
higher upstream commodity prices, the introduction of the operations of
the Lima and Toledo refineries, higher upgrading throughput and unit
margin, higher crude oil and sulphur brokering income, higher pipeline
throughput and tariffs partially offset by higher cost of sales and
operating and administrative expenses, cash taxes and interest.

6.2 Financing Activities

In the second quarter of 2008, cash used in financing activities was
$1,217 million compared with $454 million in the second quarter of 2007.
The debt issuances and repayments presented in the Consolidated
Statements of Cash Flows include multiple drawings and repayments under
revolving debt facilities. The remaining bridge financing of $741 million
in respect of the acquisition of the Lima refinery was repaid in June
2008.

6.3 Investing Activities

In the second quarter of 2008, cash used in investing activities amounted
to $667 million compared with $549 million in the second quarter of 2007.
Cash invested in both periods was used primarily for capital expenditures.

6.4 Sources of Capital

We are currently able to fund our capital programs principally by cash
provided from operating activities. We also maintain access to sufficient
capital via debt markets commensurate with the strength of our balance
sheet and continually examine our options with respect to sources of long
and short-term capital resources.

Working capital is the amount by which current assets exceed current
liabilities. At June 30, 2008, our working capital was $1,488 million
compared with a working capital deficiency of $51 million at December 31,
2007. In addition to increases in cash balances, working capital
increased due to higher feedstock and refined product inventories, higher
accounts receivable at our U.S. refining operations and higher accounts
receivable for our Canadian crude oil production. The higher working
capital from cash, accounts receivable and inventories was partially
offset by higher accounts payable, primarily for U.S. refinery feedstock
purchases.

----------------------------------------------------------------------------

June 30 Dec. 31
(millions of dollars) 2008 2007 Change
----------------------------------------------------------------------------
Current assets
Cash and cash equivalents $ 536 $ 208 $ 328 Strong earnings, sale
of 50% of Madura PSC
Accounts receivable 2,171 1,622 549 Higher crude oil prices
Inventories 1,889 1,190 699 Inclusion of Toledo
inventory; increased
Lima inventory
Prepaid expenses 66 28 38 Certain 2008 expenses
paid early in the year
---------------------------------------------------
4,662 3,048 1,614
Current liabilities
Accounts payable 1,847 1,460 (387) Higher crude oil and
gas prices; higher
royalties; inclusion
of Toledo refinery
Accrued interest payable 32 20 (12)
Income taxes payable 214 36 (178) Higher taxable income
Other accrued liabilities 852 842 (10)

Long-term debt due within Repayment of bridge
one year 229 741 512 financing offset by
capital securities
reclassed to current
---------------------------------------------------
3,174 3,099 (75)
---------------------------------------------------
Working capital $1,488 $ (51) $1,539
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Capital Structure
June 30, 2008

(millions of dollars) Outstanding Available
----------------------------------------------------------------------------
Total short-term and long-term debt $ 2,129 $ 1,588
Common shares, retained earnings and
accumulated other comprehensive income $ 13,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------

At June 30, 2008, we had unused committed long and short-term
borrowing credit facilities totalling $1.5 billion. A total of $82
million of our borrowing credit facilities were used in support of
outstanding letters of credit and an additional $44 million of letters of
credit were outstanding at June 30, 2008 supported by dedicated letters
of credit lines.

The Sunrise Oil Sands Partnership has an unsecured demand credit facility
available of $10 million for general purposes. Our proportionate share is
$5 million.

We currently have a shelf prospectus dated September 21, 2006 that
enables us to offer up to U.S. $1.0 billion of debt securities in the
United States until October 21, 2008. During the period that the
prospectus is effective, debt securities may be offered in amounts, at
prices and on terms to be determined based on market conditions at the
time of sale. As of the date of this MD&A, U.S. $750 million of debt
securities had been issued under this shelf prospectus and the remaining
amount of U.S. $250 million is eligible for issue.

On June 12, 2008, we initiated a cash tender offer to purchase any and
all of the 8.90% capital securities. As of June 12, 2008, there were U.S.
$225 million of capital securities outstanding. The tender offer expired
on July 11, 2008 at which date U.S. $ 214 million or 95% of the capital
securities had been tendered. The settlement date occurred July 11, 2008.
The remaining capital securities will be redeemed on August 14, 2008.

6.5 Credit Ratings

On March 31, 2008, DBRS upgraded our Senior Unsecured Notes and
Debentures to A (low) and our Capital Securities to BBB (high) both with
stable trends.

Our other credit ratings are available in our recently filed Annual
Information Form at www.sedar.com.

6.6 Contractual Obligations and Commercial Commitments

Refer to Husky's 2007 annual and first quarter 2008 MD&A under the
caption "Liquidity and Capital Resources," which summarizes contractual
obligations and commercial commitments.

6.7 Off Balance Sheet Arrangements

We do not utilize off balance sheet arrangements with unconsolidated
entities to enhance perceived liquidity.

We engage, in the ordinary course of business, in the securitization of
accounts receivable. At June 30, 2008 and December 31, 2007, we had no
accounts receivable sold under the securitization program. The
securitization program permits the sale of a maximum of $350 million of
accounts receivable on a revolving basis. The accounts receivable are
sold to an unrelated third party and in accordance with the agreement we
must provide a loss reserve to replace defaulted receivables. The
securitization agreement expires on January 31, 2009.

The securitization program provides us with cost effective short-term
funding for general corporate use. We account for these securitizations
as asset sales. In the event the program is terminated our liquidity
would not be materially reduced.

6.8 Transactions with Related Parties

TransAlta Power, L.P. is an indirect subsidiary of Cheung Kong
Infrastructure Holdings Ltd., which is majority owned by Hutchison
Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd., a
34.58% shareholder in Husky. TransAlta Power, L.P. is a 49.99% owner of
TransAlta Cogeneration, L.P., our partner in the Meridian cogeneration
plant in Lloydminster, Saskatchewan. We sell natural gas to the Meridian
cogeneration plant and other cogeneration plants owned by TransAlta
Power, L.P. We received the market price or negotiated medium-term
contracts based on market-related terms for these commodities. During the
first six months of 2008, we sold $64 million of natural gas to TransAlta
Power, L.P.

7. Risk Management

Husky is exposed to market risks and various operational risks. For a
detailed discussion of these risks see our 2007 Annual Information Form
filed on the Canadian Securities Administrator's web site, www.sedar.com,
the Securities Exchange Commission's web site, www.sec.gov or our web
site www.huskyenergy.com. Our financial risks are largely related to
commodity prices, exchange rates, interest rates, credit risk, changes in
fiscal policy related to royalties and taxes and others. From time to
time, we use financial and derivative instruments to manage our exposure
to these risks.

Interest Rate Risk Management

In the first six months of 2008, interest rate risk management activities
resulted in a decrease to interest expense of less than $1 million.

Husky has interest rate swaps on $200 million of long-term debt effective
February 8, 2002 whereby 6.95% was swapped for CDOR + 175 bps until July
14, 2009. During the first six months of 2008, these swaps resulted in an
offset to interest expense amounting to $1 million.

The amortization of previous interest rate swap terminations resulted in
an additional $1 million offset to interest expense in the first six
months of 2008.

Cross currency swaps resulted in an addition to interest expense of $2
million in the first six months of 2008.

Foreign Currency Risk Management

At June 30, 2008, we had the following cross currency debt swaps in place:

- U.S. $150 million at 6.25% swapped at $1.41 to $212 million at 7.41%
until June 15, 2012.

- U.S. $75 million at 6.25% swapped at $1.19 to $90 million at 5.65%
until June 15, 2012.

- U.S. $50 million at 6.25% swapped at $1.17 to $59 million at 5.67%
until June 15, 2012.

- U.S. $75 million at 6.25% swapped at $1.17 to $88 million at 5.61%
until June 15, 2012.

At June 30, 2008, we had the following freestanding derivatives in place
where Husky had entered into forward purchases of U.S. dollars to
partially offset exposure on an embedded derivative (refer to Note 16 to
the Consolidated Financial Statements):

- U.S. $119 million bought at $0.9854 for $117 million from January 2008
to June 2011.

- U.S. $119 million bought at $0.9772 for $116 million from January 2008
to June 2011.

- U.S. $119 million bought at $0.9670 for $115 million from January 2008
to June 2011.

At June 30, 2008 the cost of a U.S. dollar in Canadian currency was
$1.0186.

Our results are affected by the exchange rate between the Canadian and
U.S. dollar. The majority of our revenues are received in U.S. dollars or
from the sale of oil and gas commodities that receive prices determined
by reference to U.S. benchmark prices. The majority of our expenditures
are in Canadian dollars. An increase in the value of the Canadian dollar
relative to the U.S. dollar will decrease the revenues received from the
sale of oil and gas commodities. Correspondingly, a decrease in the value
of the Canadian dollar relative to the U.S. dollar will increase the
revenues received from the sale of oil and gas commodities.

In addition, a change in the value of the Canadian dollar against the
U.S. dollar will result in an increase or decrease in Husky's U.S. dollar
denominated debt, as expressed in Canadian dollars, as well as in the
related interest expense. At June 30, 2008, 90% or $1.9 billion of our
long-term debt was denominated in U.S. dollars. The percentage of our
long-term debt exposed to the Cdn/U.S. exchange rate decreases to 73%
when cross currency swaps are considered.

Effective July 1, 2007, our U.S. $1.5 billion of debt financing related
to the Lima acquisition was designated as a hedge of the net investment
in the U.S. refining operations, which are considered self-sustaining.
During the second quarter of 2008, we repaid our bridge financing of U.S.
$750 million. As a result, the net investment hedge is limited to the
remaining U.S. $750 million. As at June 30, 2008, unrealized foreign
exchange losses arising from the translation of the debt were $40
million, net of tax of $7 million which was recorded in "Other
Comprehensive Income."

8. Critical Accounting Estimates

Certain of our accounting policies require that we make appropriate
decisions with respect to the formulation of estimates and assumptions
that affect the reported amounts of assets, liabilities, revenues and
expenses. For a discussion about those accounting policies, please refer
to our Management's Discussion and Analysis for the year ended December
31, 2007 available at www.sedar.com.

9. Changes in Accounting Policies

Inventories

Effective January 1, 2008, we adopted the Canadian Institute of Chartered
Accountants ("CICA") section 3031, "Inventories," which replaced CICA
section 3030 of the same name. The new guidance provides additional
measurement and disclosure requirements and requires the reversal of
previous impairment write-downs when there is a change in the situation
that caused the impairment. The transitional provisions of section 3031
provided entities with the option of applying this guidance
retrospectively and restating prior periods in accordance with section
1506, "Accounting Changes" or adjusting opening retained earnings and not
restating prior periods. The adoption of this standard did not have an
impact on our financial statements.

Financial Instruments - Disclosure and Presentation

Effective January 1, 2008, we adopted CICA section 3862, "Financial
Instruments - Disclosures" and CICA section 3863, "Financial Instruments
- Presentation," which replaced CICA section 3861, "Financial Instruments
- Disclosure and Presentation." Section 3862 outlines the disclosure
requirements for financial instruments and non-financial derivatives.
This guidance prescribes an increased importance on risk disclosures
associated with recognized and unrecognized financial instruments and how
such risks are managed. Specifically, section 3862 requires disclosure of
the significance of financial instruments on our financial position. In
addition, the guidance outlines revised requirements for the disclosure
of qualitative and quantitative information regarding exposure to risks
arising from financial instruments.

The presentation requirements under section 3863 are relatively unchanged
from section 3861. Refer to Note 16 to the Consolidated Financial
Statements for the additional disclosures under section 3862.

Capital Disclosures

Effective January 1, 2008, we adopted CICA section 1535, "Capital
Disclosures." This new guidance requires disclosure about our objectives,
policies and processes for managing capital. These disclosures include a
description of what we manage as capital, the nature of externally
imposed capital requirements, how the requirements are incorporated into
our management of capital, whether the requirements have been complied
with, or consequence of non-compliance and an explanation of how we are
meeting our objectives for managing capital. In addition, quantitative
disclosures regarding capital are required. Refer to Note 17 to the
Consolidated Financial Statements.

International Financial Reporting Standards

In January 2006, the Canadian Accounting Standards Board ("AcSB") adopted
a strategic plan for the direction of accounting standards in Canada. As
part of the AcSB's strategic plan, Canadian publicly accountable entities
will be required to report under International Financial Reporting
Standards ("IFRS"), which will replace Canadian generally accepted
accounting principles ("GAAP") for years beginning on or after January 1,
2011. An omnibus exposure draft was issued by the AcSB in the second
quarter of 2008, which incorporates IFRS into the CICA Handbook and
prescribes the transitional provisions for adopting IFRS. Currently, we
are assessing the effects of adoption and developing a plan accordingly.
We will continue to monitor any changes in the adoption of IFRS and will
update plans as necessary.

10. Outstanding Share Data
----------------------------------------------------------------------------

July 15 December 31

(in thousands) 2008 2007
----------------------------------------------------------------------------
Issued and outstanding
Number of common shares 849,143 848,960
Number of stock options 27,481 30,131
Number of stock options exercisable 7,456 4,494
----------------------------------------------------------------------------
----------------------------------------------------------------------------

11. Reader Advisories

This MD&A should be read in conjunction with the Consolidated Financial
Statements and related Notes. Readers are encouraged to refer to Husky's
MD&A and Consolidated Financial Statements and 2007 Annual Information
Form filed in 2008 with Canadian regulatory agencies and Form 40-F filed
with the Securities and Exchange Commission, the U.S. regulatory agency.
These documents are available at www.sedar.com, at www.sec.gov and at
www.huskyenergy.com.

Use of Pronouns and Other Terms Denoting Husky

In this MD&A the pronouns "we," "our" and "us" and the terms "Husky" and
"the Company" denote the corporate entity Husky Energy Inc. and its
subsidiaries on a consolidated basis.

Standard Comparisons in this Document

Unless otherwise indicated, the discussions in this MD&A with respect to
results for the three months ended June 30, 2008 are compared with
results for the three months ended June 30, 2007 and results for the six
months ended June 30, 2008 are compared with results for the six months
ended June 30, 2007. Discussions with respect to Husky's financial
position as at June 30, 2008 are compared with its financial position at
December 31, 2007.

Additional Reader Guidance

- The Consolidated Financial Statements and comparative financial
information included in this Interim Report have been prepared in
accordance with Canadian GAAP. - All dollar amounts are in millions of
Canadian dollars, unless otherwise indicated.

- Unless otherwise indicated, all production volumes quoted are gross,
which represent the Company's working interest share before royalties.

- Prices quoted include or exclude the effect of hedging as indicated.

Non-GAAP Measures

Disclosure of Cash Flow from Operations

Management's Discussion and Analysis contains the term "cash flow from
operations," which should not be considered an alternative to, or more
meaningful than "cash flow - operating activities" as determined in
accordance with generally accepted accounting principles as an indicator
of our financial performance. Cash flow from operations or earnings is
presented in our financial reports to assist management and investors in
analyzing operating performance by business in the stated period. Our
determination of cash flow from operations may not be comparable to that
reported by other companies. Cash flow from operations equals net
earnings plus items not affecting cash which include accretion,
depletion, depreciation and amortization, future income taxes, foreign
exchange and other non-cash items.

The following table shows the reconciliation of cash flow from operations
to cash flow - operating activities for the periods noted:

----------------------------------------------------------------------------

Three months Six months
ended June 30 ended June 30

(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Non-GAAP Cash flow from operations $ 2,090 $ 1,257 $ 3,631 $ 2,581
Settlement of asset
retirement obligations (7) (7) (24) (21)
Change in non-cash working
capital (29) (114) (326) (752)
----------------------------------------------------------------------------
GAAP Cash flow - operating
activities $ 2,054 $ 1,136 $ 3,281 $ 1,808
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Disclosure of Operating Netback

Operating netback is a common non-GAAP metric used in the oil and gas
industry. This measurement helps management and investors to evaluate the
specific operating performance by product at the oil and gas lease level.
It is equal to product revenue less transportation costs, royalties and
lease operating costs divided by either a barrel of oil equivalent or an
mcf of gas equivalent.

Cautionary Note Required by National Instrument 51-101

The Company uses the terms barrels of oil equivalent ("boe") and thousand
cubic feet of gas equivalent ("mcfge"), which are calculated on an energy
equivalence basis whereby one barrel of crude oil is equivalent to six
thousand cubic feet of natural gas. Readers are cautioned that the terms
boe and mcfge may be misleading, particularly if used in isolation. This
measure is primarily applicable at the burner tip and does not represent
value equivalence at the wellhead.

Husky's disclosure of reserves data and other oil and gas information is
made in reliance on an exemption granted to Husky by Canadian securities
regulatory authorities, which permits Husky to provide disclosure
required by and consistent with the requirements of the United States
Securities and Exchange Commission and the Financial Accounting Standards
Board in the United States in place of much of the disclosure expected by
National Instrument 51-101, "Standards of Disclosure for Oil and Gas
Activities." Please refer to "Disclosure of Exemption Under National
Instrument 51-101" on page 2 of our Annual Information Form for the year
ended December 31, 2007 filed with securities regulatory authorities for
further information.

Abbreviations

bbls barrels
bps basis points
mbbls thousand barrels
mbbls/day thousand barrels per day
mmbbls million barrels
mcf thousand cubic feet
mmcf million cubic feet
mmcf/day million cubic feet per day
bcf billion cubic feet
tcf trillion cubic feet
boe barrels of oil equivalent
mboe thousand barrels of oil equivalent
mboe/day thousand barrels of oil equivalent per day
mmboe million barrels of oil equivalent
mcfge thousand cubic feet of gas equivalent
GJ gigajoule
mmbtu million British Thermal Units
mmlt million long tons
NGL natural gas liquids
WTI West Texas Intermediate
NYMEX New York Mercantile Exchange
NIT NOVA Inventory Transfer
LIBOR London Interbank Offered Rate
CDOR Certificate of Deposit Offered Rate
SEDAR System for Electronic Document Analysis and Retrieval
FPSO Floating production, storage and offloading vessel
FEED Front-end engineering design

Terms

Bitumen A naturally occurring viscous mixture consisting
mainly of pentanes and heavier hydrocarbons. It is
more viscous than 10 degrees API
Capital Employed Short- and long-term debt and shareholders' equity
Capital Expenditures Includes capitalized administrative expenses and
capitalized interest but does not include proceeds
or other assets
Capital Program Capital expenditures not including capitalized
administrative expenses or capitalized interest
Cash Flow from Earnings from operations plus non-cash charges
Operations before settlement of asset retirement obligations
and change in non-cash working capital
Corporate Reinvestment Net capital expenditures (capital expenditures net
Ratio of proceeds from asset sales) plus corporate
acquisitions (net assets acquired) divided by cash
flow from operations
Dated Brent Prices which are dated less than 15 days prior to
loading for delivery
Debt to Capital Total debt divided by total debt and shareholders'
Employed equity
Delineation Well A well in close proximity to an oil or gas discovery
well that helps determine the areal extent of the
reservoir
Diluent A lighter gravity liquid hydrocarbon, usually
condensate or synthetic oil, added to heavy oil to
facilitate transmissibility through a pipeline
Embedded Derivative Implicit or explicit term(s) in a contract that
affects some or all of the cash flows or the value
of other exchanges required by the contract
Equity Shares, retained earnings and accumulated other
comprehensive income
Feedstock Raw materials which are processed into petroleum
products
Front-end Engineering Preliminary engineering and design planning, which
Design among other things, identifies project objectives,
scope, alternatives, specifications, risks, costs,
schedule and economics
Glory Hole An excavation in the seabed where the wellheads and
other equipment are situated to protect them from
scouring icebergs
Gross/Net Acres/Wells Gross refers to the total number of acres/wells in
which an interest is owned. Net refers to the sum of
the fractional working interests owned by a company
Gross Reserves/ A company's working interest share of
Production reserves/production before deduction of royalties
Hectare One hectare is equal to 2.47 acres
Near-month Prices Prices quoted for contracts for settlement during
the next month
NOVA Inventory Exchange or transfer of title of gas that has been
Transfer received into the NOVA pipeline system but not yet
delivered to a connecting pipeline
Return on Capital Net earnings plus after tax interest expense divided
Employed by average capital employed
Return on Shareholders' Net earnings divided by average shareholders' equity
Equity
Stratigraphic Well A geologically directed test well to obtain
information. These wells are usually drilled without
the intention of being completed for production
Synthetic Oil A mixture of hydrocarbons derived by upgrading heavy
crude oils, including bitumen, through a process
that reduces the carbon content and increases the
hydrogen content
Three Dimensional Seismic imaging which uses a grid of numerous cables
(3-D) Seismic rather than a few lines stretched in one line
Total Debt Long-term debt including current portion and bank
operating loans
Turnaround Scheduled performance of plant or facility
maintenance

12. Forward-Looking Statements and Information

Certain statements in this release and Interim Report are forward-looking
statements and information (collectively "forward-looking statements"),
within the meaning of the applicable Canadian securities legislation,
Section 21E of the United States Securities Exchange Act of 1934, as
amended, and Section 27A of the United States Securities Act of 1933, as
amended. We hereby provide cautionary statements identifying important
factors that could cause our actual results to differ materially from
those projected in these forward-looking statements. Any statements that
express, or involve discussions as to, expectations, beliefs, plans,
objectives, assumptions or future events or performance (often, but not
always, through the use of words or phrases such as "will likely result,"
"are expected to," "will continue," "is anticipated," "estimated,"
"intend," "plan," "projection," "could," "vision," "goals," "objective,"
"target," "schedules" and "outlook") are not historical facts and are
forward-looking and may involve estimates and assumptions and are subject
to risks, uncertainties and other factors some of which are beyond our
control and difficult to predict. Accordingly, these factors could cause
actual results or outcomes to differ materially from those expressed in
the forward-looking statements. Therefore, any such forward-looking
statements are qualified in their entirety by reference to the factors
discussed throughout this release. In particular, forward-looking
statements in this release and Interim Report include, but are not
limited to: our 2008 revised production guidance and capital spending
guidance, our development plans for the North Amethyst, West White Rose
oil fields and South White Rose oil field extension, our plans to
undertake a 3-D seismic acquisition program in the Jeanne d'Arc Basin and
our plans to participate in an exploration well in the Flemish Pass
Basin, our production optimization plans for the Tucker in-situ oil sands
project, our Sunrise multiphase development plans, our development plans
for the McMullen property, our Caribou and Saleski oil sands projects
plans, our Northwest Territories exploration program, our exploration and
delineation drilling plans for the South China Sea, the receipt of an
extension of the PSC for the Madura BD natural gas and NGL field and
regulatory approval for the East Bawean II exploration block two-well
work program, our 2-D seismic acquisition programs and completion of an
aero-gravity and magnetic survey for offshore Greenland, our plans to
install various enhanced recovery schemes in Western Canada intended to
increase reserves and our review options in respect of reconfiguring and
expanding the Lima refinery and our plans to modify the Toledo refinery.

Although we believe that the expectations reflected by the
forward-looking statements presented in this release and Interim Report
are reasonable, our forward-looking statements have been based on
assumptions and factors concerning future events that may prove to be
inaccurate. Those assumptions and factors are based on information
currently available to us about ourselves and the businesses in which we
operate. Information used in developing forward-looking statements has
been acquired from various sources including third party consultants,
suppliers, regulators and other sources. In some instances, material
assumptions are disclosed elsewhere in this release and Interim Report in
respect of forward-looking statements. We caution the reader that the
following list of assumptions is not exhaustive. The material factors and
assumptions used to develop the forward-looking statements include but
are not limited to:

- no significant adverse changes to energy markets, competitive
conditions, the supply and demand for crude oil, natural gas, NGL and
refined petroleum products, or the political, economic and social
stability of the jurisdictions in which we operate;

- no significant delays of the development, construction or commissioning
of our projects that may result from the inability of suppliers to meet
their commitments, lack of regulatory approvals or other governmental
actions, harsh weather or other calamitous event;

- no significant disruption of our operations such as may result from
harsh weather, natural disaster, accident, civil unrest or other
calamitous event;

- no significant unexpected technological or commercial difficulties that
adversely affect our exploration, development, production, processing or
transportation;

- continuing availability of economical capital resources; demand for our
products and our cost of operations;

- no significant adverse legislative and regulatory changes, in
particular changes to the legislation and regulation governing fiscal
regimes and environmental issues; environmental risks and liability under
provincial/state, federal or other jurisdictions;

- stability of general domestic and global economic, market and business
conditions; and

- no significant increase in the cost of our major growth projects.

Because actual results or outcomes could differ materially from those
expressed in any forward-looking statements, investors should not place
undue reliance on any such forward-looking statements. By their nature,
forward-looking statements involve numerous assumptions, inherent risks
and uncertainties, both general and specific, which contribute to the
possibility that the predicted outcomes will not occur. The risks,
uncertainties and other factors, many of which are beyond our control,
that could influence actual results include, but are not limited to:

- the prices we receive for our crude and natural gas production;

- demand for our products and our cost of operations;

- our ability to replace our proved oil and gas reserves in a
cost-effective manner;

- the effect of weather and other environmental conditions;

- inability to obtain regulatory approvals to operate existing properties
or develop significant growth projects;

- competitive actions of other companies, including increased competition
from other oil and gas companies;

- business interruptions because of unexpected events such as fires,
blowouts, freeze-ups, equipment failures and other similar events
affecting us or other parties whose operations or assets directly or
indirectly affect us and that may or may not be financially recoverable;

- fluctuations in interest rates and foreign currency exchange rates;

- actions by governmental authorities, including changes in environmental
and other regulations that may impose operating costs or restrictions in
areas where we operate; and

- the inability to reach our estimated production levels from existing
and future oil and gas development projects as a result of technological,
commercial difficulties or other risk factor.

These risks, uncertainties and other factors are discussed in our Annual
Information Form and our Form 40-F, available at www.sedar.com and
www.sec.gov, respectively.

Further, any forward-looking statement speaks only as of the date on
which such statement is made, and, except as required by applicable law,
we undertake no obligation to update any forward-looking statement to
reflect events or circumstances after the date on which such statement is
made or to reflect the occurrence of unanticipated events. New factors
emerge from time to time, and it is not possible for management to
predict all of such factors and to assess in advance the impact of each
such factor on our business or the extent to which any factor, or
combination of factors, may cause actual results to differ materially
from those contained in any forward-looking statement.

CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
----------------------------------------------------------------------------

June 30 December 31

(millions of dollars, except share data) 2008 2007
----------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 536 $ 208
Accounts receivable 2,171 1,622
Inventories 1,889 1,190
Prepaid expenses 66 28
----------------------------------------------------------------------------
4,662 3,048

Property, plant and equipment (note 6) 31,062 29,407
Less accumulated depletion, depreciation and
amortization 12,460 11,602
----------------------------------------------------------------------------
18,602 17,805
Goodwill (note 8) 675 660
Contribution receivable (note 6) 1,183 -
Other assets 174 184
----------------------------------------------------------------------------
$ 25,296 $ 21,697
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 2,945 $ 2,358
Long-term debt due within one year (note 10) 229 741
----------------------------------------------------------------------------
3,174 3,099
Long-term debt (note 10) 1,900 2,073
Contribution payable (note 6) 1,339 -
Other long-term liabilities (note 11) 959 918
Future income taxes 4,616 3,957
Shareholders' equity
Common shares (note 13) 3,559 3,551
Retained earnings 9,806 8,176
Accumulated other comprehensive income (57) (77)
----------------------------------------------------------------------------
13,308 11,650
----------------------------------------------------------------------------
$ 25,296 $ 21,697
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares outstanding (millions) (note 13) 849.1 849.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.

Consolidated Statements of Earnings and Comprehensive Income
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

(millions of dollars, except share
data) (unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Sales and operating revenues, net of
royalties $ 7,199 $ 3,163 $ 12,285 $ 6,407
Costs and expenses
Cost of sales and operating expenses 4,666 1,701 7,973 3,480
Selling and administration expenses 71 52 122 90
Stock-based compensation (note 13) 114 43 71 64
Depletion, depreciation and
amortization 436 440 886 873
Interest - net (note 10) 41 22 87 43
Foreign exchange (note 10) 6 (36) 16 (37)
Other - net (74) (51) (75) (45)
----------------------------------------------------------------------------
5,260 2,171 9,080 4,468
----------------------------------------------------------------------------
Earnings before income taxes 1,939 992 3,205 1,939
----------------------------------------------------------------------------
Income taxes
Current 234 66 459 138
Future 342 205 496 430
----------------------------------------------------------------------------
576 271 955 568
----------------------------------------------------------------------------
Net earnings 1,363 721 2,250 1,371
Other comprehensive income (note 16)
Derivatives designated as cash flow
hedges, net of tax (3) 2 (5) 4
Cumulative foreign currency
translation adjustment (27) - 65 -
Hedge of net investment, net of tax 11 - (40) -
----------------------------------------------------------------------------
(19) 2 20 4
----------------------------------------------------------------------------
Comprehensive income $ 1,344 $ 723 $ 2,270 $ 1,375
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share
Basic and diluted $ 1.61 $ 0.85 $ 2.65 $ 1.61
Weighted average number of common
shares outstanding (millions)
Basic and diluted 849.1 848.7 849.1 848.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.

Consolidated Statements of Changes in Shareholders' Equity
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

(millions of dollars) (unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Common shares
Beginning of period $ 3,555 $ 3,536 $ 3,551 $ 3,533
Options exercised 4 11 8 14
----------------------------------------------------------------------------
End of period 3,559 3,547 3,559 3,547
----------------------------------------------------------------------------
Retained earnings
Beginning of period 8,783 6,317 8,176 6,087
Net earnings 1,363 721 2,250 1,371
Dividends on common shares
Ordinary (340) (212) (620) (424)
Special - - - (212)
Adoption of financial instruments - - - 4
----------------------------------------------------------------------------
End of period 9,806 6,826 9,806 6,826
----------------------------------------------------------------------------
Accumulated other comprehensive
income
Beginning of period (38) (16) (77) -
Adoption of financial instruments - - - (18)
Other comprehensive income (note 16)
Derivatives designated as cash flow
hedges, net of tax (3) 2 (5) 4
Cumulative foreign currency
translation adjustment (27) - 65 -
Hedge of net investment, net of tax 11 - (40) -
----------------------------------------------------------------------------
(19) 2 20 4
----------------------------------------------------------------------------
End of period (57) (14) (57) (14)
----------------------------------------------------------------------------
Shareholders' equity $ 13,308 $ 10,359 $ 13,308 $ 10,359
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.

Consolidated Statements of Cash Flows
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

(millions of dollars) (unaudited) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating activities
Net earnings $ 1,363 $ 721 $ 2,250 $ 1,371
Items not affecting cash
Accretion (note 11) 14 10 27 22
Depletion, depreciation and
amortization 436 440 886 873
Future income taxes 342 205 496 430
Foreign exchange 3 (69) 34 (79)
Other (68) (50) (62) (36)
Settlement of asset retirement
obligations (note 11) (7) (7) (24) (21)
Change in non-cash working capital
(note 7) (29) (114) (326) (752)
----------------------------------------------------------------------------
Cash flow - operating activities 2,054 1,136 3,281 1,808
----------------------------------------------------------------------------
Financing activities
Bank operating loans financing - net (77) (83) - -
Long-term debt issue 372 1,432 747 1,867
Long-term debt repayment (1,237) (1,432) (1,512) (1,967)
Proceeds from exercise of stock
options 1 3 2 4
Dividends on common shares (340) (212) (620) (636)
Other - - (8) -
Change in non-cash working capital
(note 7) 64 (162) 73 56
----------------------------------------------------------------------------
Cash flow - financing activities (1,217) (454) (1,318) (676)
----------------------------------------------------------------------------
Available for investing 837 682 1,963 1,132
----------------------------------------------------------------------------
Investing activities
Capital expenditures (726) (647) (1,578) (1,381)
Joint venture arrangement (note 6) 127 - 127 -
Asset sales 4 327 34 327
Other (14) (36) 5 (38)
Change in non-cash working capital
(note 7) (58) (193) (223) (349)
----------------------------------------------------------------------------
Cash flow - investing activities (667) (549) (1,635) (1,441)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 170 133 328 (309)
Cash and cash equivalents, beginning
of period 366 - 208 442
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ 536 $ 133 $ 536 $ 133
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.

Notes to the Consolidated Financial Statements

Six months ended June 30, 2008 (unaudited)
Except where indicated, all dollar amounts are in millions.

Note 1 Segmented Financial Information
----------------------------------------------------------------------------
Upstream Midstream
Infrastructure
and
Upgrading Marketing
2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Three months ended June 30
Sales and operating revenues,
net of royalties $2,424 $1,593 $ 648 $ 229 $3,909 $2,521
Costs and expenses
Operating, cost of sales,
selling and general 328 295 546 186 3,779 2,445
Depletion, depreciation and
amortization 352 407 7 4 7 7
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
680 702 553 190 3,786 2,452
----------------------------------------------------------------------------
Earnings (loss) before income
taxes 1,744 891 95 39 123 69
Current income taxes 99 3 14 - 28 29
Future income taxes 406 252 14 10 9 (8)
----------------------------------------------------------------------------
Net earnings (loss) $1,239 $ 636 $ 67 $ 29 $ 86 $ 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - Three
months ended June 30 (2) $ 625 $ 520 $ 28 $ 74 $ 5 $ 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate and
Downstream Eliminations (1) Total
U.S.
Canadian Refining
Refined and
Products Marketing
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months
ended June 30
Sales and
operating
revenues,
net of
royalties $ 982 $ 709 $2,553 $ - $(3,317) $(1,889) $7,199 $3,163
Costs and
expenses
Operating, cost
of sales,
selling and
general 912 620 2,262 - (3,050) (1,801) 4,777 1,745
Depletion,
depreciation
and
amortization 20 15 43 - 7 7 436 440
Interest - net - - - - 41 22 41 22
Foreign
exchange - - - - 6 (36) 6 (36)
----------------------------------------------------------------------------
932 635 2,305 - (2,996) (1,808) 5,260 2,171
----------------------------------------------------------------------------
Earnings (loss)
before income
taxes 50 74 248 - (321) (81) 1,939 992
Current income
taxes 7 7 59 - 27 27 234 66
Future income
taxes 8 14 30 - (125) (63) 342 205
----------------------------------------------------------------------------
Net earnings
(loss) $ 35 $ 53 $ 159 $ - $ (223) $ (45) $1,363 $ 721
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital
expenditures -
Three
months ended
June 30 (2) $ 28 $ 43 $ 34 $ - $ 14 $ 11 $ 734 $ 653
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Upstream Midstream
Infrastructure
and
Upgrading Marketing
2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
Six months ended June 30
Sales and operating revenues,
net of royalties $ 4,253 $ 3,158 $1,131 $ 588 $7,011 $5,076
Costs and expenses
Operating, cost of sales,
selling and general 741 618 920 464 6,770 4,906
Depletion, depreciation and
amortization 742 806 13 10 15 14
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
1,483 1,424 933 474 6,785 4,920
----------------------------------------------------------------------------
Earnings (loss) before income
taxes 2,770 1,734 198 114 226 156
Current income taxes 265 25 36 1 58 45
Future income taxes 549 493 23 33 10 3
----------------------------------------------------------------------------
Net earnings (loss) $ 1,956 $ 1,216 $ 139 $ 80 $ 158 $ 108
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures - Six
months ended June 30 (2) $ 1,423 $ 1,137 $ 50 $ 122 $ 15 $ 41
Goodwill additions - Six
months ended June 30 $ - $ - $ - $ - $ - $ -
Total assets - As at June 30 $14,708 $13,974 $1,497 $1,193 $1,300 $1,147
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate and
Downstream Eliminations (1) Total
U.S.
Canadian Refining
Refined and
Products Marketing
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months
ended June 30
Sales and
operating
revenues, net
of royalties $1,704 $1,327 $3,882 $ - $(5,696) $(3,742) $12,285 $ 6,407
Costs and
expenses
Operating,
cost of sales,
selling and
general 1,571 1,192 3,558 - (5,469) (3,591) 8,091 3,589
Depletion,
depreciation
and
amortization 40 31 62 - 14 12 886 873
Interest - net - - 1 - 86 43 87 43
Foreign
exchange - - - - 16 (37) 16 (37)
----------------------------------------------------------------------------
1,611 1,223 3,621 - (5,353) (3,573) 9,080 4,468
----------------------------------------------------------------------------
Earnings
(loss) before
income taxes 93 104 261 - (343) (169) 3,205 1,939
Current income
taxes 13 15 37 - 50 52 459 138
Future income
taxes 15 16 57 - (158) (115) 496 430
----------------------------------------------------------------------------
Net earnings
(loss) $ 65 $ 73 $ 167 $ - $ (235) $ (106) $ 2,250 $ 1,371
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital
expenditures -
Six months
ended June 30
(2) $ 47 $ 83 $ 41 $ - $ 26 $ 16 $ 1,602 $ 1,399
Goodwill
additions -
Six months
ended June 30 $ - $ - $ - $ - $ - $ - $ - $ -
Total assets -
As at June 30 $1,630 $1,304 $5,404 $ - $ 757 $ 351 $25,296 $17,969
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Eliminations relate to sales and operating revenues between segments
recorded at transfer prices based on current market prices, and to
unrealized intersegment profits in inventories.
(2) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.

Geographical Financial Information
----------------------------------------------------------------------------
Other
Canada United States International Total
2008 2007 2008 2007 2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months
ended June 30
Sales and
operating
revenues,
net of
royalties $ 4,143 $ 2,828 $ 2,957 $ 262 $ 99 $ 73 $ 7,199 $ 3,163
Capital
expenditures
(1) 665 628 34 - 35 25 734 653

Six months
ended June 30
Sales and
operating
revenues,
net of
royalties $ 7,527 $ 5,664 $ 4,575 $ 598 $ 183 $ 145 $12,285 $ 6,407
Capital
expenditures
(1) 1,496 1,369 41 - 65 30 1,602 1,399
As at June 30
Property,
plant and
equipment,
net $14,875 $15,378 $ 3,369 $ 3 $ 358 $ 350 $18,602 $ 15,731
Goodwill (2) 160 160 515 - - - 675 160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.
(2) Changes in goodwill for the U.S. arise from translation of goodwill in
our self-sustaining U.S. operations.

Note 2 Significant Accounting Policies

The interim consolidated financial statements of Husky Energy Inc.
("Husky" or "the Company") have been prepared by management in accordance
with accounting principles generally accepted in Canada. The interim
consolidated financial statements have been prepared following the same
accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2007, except
as noted below. The interim consolidated financial statements should be
read in conjunction with the consolidated financial statements and the
notes thereto in the Company's annual report for the year ended December
31, 2007. Certain prior years' amounts have been reclassified to conform
with current presentation.

Note 3 Changes in Accounting Policies

Inventories

Effective January 1, 2008, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") section 3031, "Inventories," which
replaced CICA section 3030 of the same name. The new guidance provides
additional measurement and disclosure requirements and requires the
Company to reverse previous impairment write-downs when there is a change
in the situation that caused the impairment. The transitional provisions
of section 3031 provided entities with the option of applying this
guidance retrospectively and restating prior periods in accordance with
section 1506, "Accounting Changes" or adjusting opening retained earnings
and not restating prior periods. The adoption of this standard did not
have an impact on the Company's financial statements.

Note 4 New Disclosures

a) Financial Instruments - Disclosure and Presentation

Effective January 1, 2008, the Company adopted CICA section 3862,
"Financial Instruments - Disclosures" and CICA section 3863, "Financial
Instruments - Presentation," which replaced CICA section 3861, "Financial
Instruments - Disclosure and Presentation." Section 3862 outlines the
disclosure requirements for financial instruments and non-financial
derivatives. This guidance prescribes an increased importance on risk
disclosures associated with recognized and unrecognized financial
instruments and how such risks are managed. Specifically, section 3862
requires disclosure of the significance of financial instruments on the
Company's financial position. In addition, the guidance outlines revised
requirements for the disclosure of qualitative and quantitative
information regarding exposure to risks arising from financial
instruments.

The presentation requirements under section 3863 are relatively unchanged
from section 3861. Refer to Note 16, "Financial Instruments and Risk
Management" for the additional disclosures under section 3862.

b) Capital Disclosures

Effective January 1, 2008, the Company adopted CICA section 1535,
"Capital Disclosures." This new guidance requires disclosure about the
Company's objectives, policies and processes for managing capital. These
disclosures include a description of what the Company manages as capital,
the nature of externally imposed capital requirements, how the
requirements are incorporated into the Company's management of capital,
whether the requirements have been complied with, or consequence of
non-compliance and an explanation of how the Company is meeting its
objectives for managing capital. In addition, quantitative disclosures
regarding capital are required. Refer to Note 17, "Capital Disclosures."

Note 5 Pending Accounting Pronouncements

Goodwill and Intangible Assets

In February 2008, the CICA issued CICA section 3064, "Goodwill and
Intangible Assets," which will replace CICA section 3062 of the same
name. As a result of issuing this guidance, CICA section 3450, "Research
and Development Costs," and Emerging Issues Committee Abstract No. 27,
"Revenues and Expenditures during the Pre-Operating Period" will be
withdrawn. This new guidance reinforces a principles-based approach to
the recognition of costs as assets in accordance with the definition of
an asset and the criteria for asset recognition under CICA section 1000,
"Financial Statement Concepts." Moreover, section 3064 clarifies the
application of the concept of matching revenues and expenses in section
1000 to eliminate the current practice of recognizing as assets items
that do not meet the definition and recognition criteria. Under this new
guidance, fewer items meet the criteria for capitalization. Section 3064
is effective for Husky on January 1, 2009. Intangible assets recognized
prior to January 1, 2009 that do not meet the recognition or measurement
criteria as outlined in section 3064 are accounted for in accordance with
CICA section 1506, "Accounting Changes." An intangible item that was
originally recognized as an expense is not recognized as part of the cost
of an intangible asset upon transition to section 3064. The Company is
currently determining the impact of this standard.

Note 6 Joint Ventures

a) BP

On March 31, 2008, the Company completed a transaction with BP, which
resulted in the formation of a 50/50 joint venture upstream entity and a
50/50 joint venture downstream entity.

The upstream entity is a partnership to which Husky has contributed the
Sunrise oil sands assets with a fair value of U.S. $2.5 billion as at
January 1, 2008 plus capital expenditures for the three-month period
ended March 31, 2008 of $41 million. BP's contribution was U.S. $250
million cash and a contribution receivable for the balance of U.S. $2.25
billion and $41 million. The contribution receivable accretes at a rate
of 6% and is payable between March 31, 2008 and December 31, 2015 with
the final balance due and payable by December 31, 2015. The upstream
entity is included as part of the Upstream segment.

The downstream entity is a limited liability company ("LLC") to which BP
has contributed the Toledo refinery with a fair value of U.S. $2.5
billion, plus capital expenditures for the three-month period ended March
31, 2008 of U.S. $12 million and inventories of U.S. $372 million, less
inventory related payables of U.S. $109 million and adjusted earnings of
U.S. $14 million. Husky's contribution was U.S. $250 million cash and a
contribution payable for the balance of U.S. $2.5 billion. The
contribution payable accretes at a rate of 6% and is payable between
March 31, 2008 and December 31, 2015 with the final balance due and
payable by December 31, 2015. The timing of payments during this period
will be determined by the capital expenditures made at the refinery
during this same period. The downstream entity is included as part of the
U.S. Refining and Marketing segment. This entity is a self-sustaining
foreign operation.

During the second quarter of 2008, the operator of the refinery reported
adjustments to capital expenditures, inventory, inventory related
payables and other items contributed to the downstream LLC on March 31,
2008. As a result, BP's revised contributions were capital expenditures
of U.S. $11 million, inventories of U.S. $388 million, other net assets
of U.S. $3 million, less inventory related payables of U.S. $23 million
and adjusted earnings of U.S. $39 million. The adjustments resulted in an
increase to the contribution payable from Husky of U.S. $79 million.

Both joint ventures are being accounted for using proportionate
consolidation. The amounts recorded in the financial statements represent
the Company's 50% interest in the joint ventures.

b) CNOOC Southeast Asia Limited

In April 2008, a subsidiary of the Company, Husky Oil Madura Partnership
("HOMP"), entered into an agreement with CNOOC Southeast Asia Limited
("CNOOCSE"), which resulted in the acquisition by CNOOCSE of a 50% equity
interest in Husky Oil (Madura) Limited, a subsidiary of HOMP, for a
consideration of $127 million (U.S. $125 million) resulting in a gain of
$69 million included in other - net in the Consolidated Statements of
Earnings and Comprehensive Income. Husky Oil (Madura) Limited holds a
100% interest in the Madura Strait Production Sharing Contract. The
resulting joint venture arrangement is being accounted for using the
proportionate consolidation method.

Note 7 Cash Flows - Change in Non-cash Working Capital
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2008 2007 2008 2007
----------------------------------------------------------------------------
a) Change in non-cash working capital was
as follows:
Decrease (increase) in non-cash working
capital
Accounts receivable $ (211) $ 147 $ (535) $ 149
Inventories (238) (99) (486) (91)
Prepaid expenses (35) (143) (36) (144)
Accounts payable and accrued
liabilities 461 (374) 581 (959)
----------------------------------------------------------------------------
Change in non-cash working capital $ (23) $ (469) $ (476) $ (1,045)
----------------------------------------------------------------------------
----------------------------------------------------------------------------Rela
ing to:
Operating activities $ (29) $ (114) $ (326) $ (752)
Financing activities 64 (162) 73 56
Investing activities (58) (193) (223) (349)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Other cash flow information:
Cash taxes paid $ 110 $ 72 $ 281 $ 840
Cash interest paid 41 39 82 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Note 8 Goodwill
Three months Six months
ended June 30 ended June 30

2008 2007 2008 2007
----------------------------------------------------------------------------
Balance at beginning of period $ 680 $ 160 $ 660 $ 160
Foreign currency translation of goodwill
in self-sustaining U.S. operations (5) - 15 -
----------------------------------------------------------------------------
Balance at June 30 $ 675 $ 160 $ 675 $ 160
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Note 9 Bank Operating Loans

At June 30, 2008, the Company had unsecured short-term borrowing lines of
credit with banks totalling $270 million (December 31, 2007 - $270
million). As at June 30, 2008 and December 31, 2007, there were no bank
operating loans outstanding. As of June 30, 2008, letters of credit under
these lines of credit totalled $82 million (December 31, 2007 - $73
million).

The Sunrise Oil Sands Partnership has an unsecured demand credit facility
of $10 million available for general purposes. The Company's
proportionate share is $5 million. As at June 30, 2008, there was no
balance outstanding under this credit facility.

Note 10 Long-term Debt
June 30 Dec. 31 June 30 Dec. 31

Maturity 2008 2007 2008 2007
----------------------------------------------------------------------------
Cdn $ Amount U.S. $ Denominated
Long-term debt
Medium-term notes 2009 $ 203 $ 203 $ - $ -
6.25% notes 2012 407 395 400 400
7.55% debentures 2016 204 198 200 200
6.20% notes 2017 306 296 300 300
6.15% notes 2019 306 296 300 300
8.90% capital securities 2028 - 223 - 225
6.80% notes 2037 458 445 450 450
Debt issue costs (1) (18) (20) - -
Unwound interest rate swaps 34 37 - -
----------------------------------------------------------------------------
$ 1,900 $ 2,073 $ 1,650 $ 1,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt due within
one year
Bridge financing 2008 $ - $ 741 $ - $ 750
8.90% capital securities 2008 229 - 225 -
----------------------------------------------------------------------------
$ 229 $ 741 $ 225 $ 750
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated using the effective interest rate method.

On June 12, 2008, Husky initiated a cash tender offer to purchase any
and all of the 8.90% capital securities. As of June 12, 2008, there were
U.S. $225 million of capital securities outstanding. The full tender
offer consideration for the capital securities was U.S. $1,010 per U.S.
$1,000 principal amount of capital securities plus accrued and unpaid
interest. The tender offer expired on July 11, 2008 at which date U.S.
$214 million or 95% of the capital securities had been tendered. The
settlement date occurred July 11, 2008. The remaining capital securities
will be redeemed on August 14, 2008.

Interest - net consisted of:
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2008 2007 2008 2007
----------------------------------------------------------------------------
Long-term debt $ 43 $ 26 $ 91 $ 54
Short-term debt 1 2 2 3
----------------------------------------------------------------------------
44 28 93 57
Amount capitalized - (5) - (8)
----------------------------------------------------------------------------
44 23 93 49
Interest income (3) (1) (6) (6)
----------------------------------------------------------------------------
$ 41 $ 22 $ 87 $ 43

----------------------------------------------------------------------------
----------------------------------------------------------------------------

Foreign exchange consisted of:
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2008 2007 2008 2007
----------------------------------------------------------------------------
(Gain) loss on translation of U.S. dollar
denominated long-term debt $ (10) $ (101) $ 34 $ (115)
Cross currency swaps 3 32 (11) 36
Contribution receivable 11 - 11 -
Other (gains) losses 2 33 (18) 42
----------------------------------------------------------------------------
Loss (gain) $ 6 $ (36) $ 16 $ (37)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Note 11 Other Long-term Liabilities

Asset Retirement Obligations

Changes to asset retirement obligations were as follows:
----------------------------------------------------------------------------
Six months
ended June 30

2008 2007
----------------------------------------------------------------------------
Asset retirement obligations at beginning of year $ 662 $ 622
Liabilities incurred 29 16
Liabilities disposed (2) (14)
Liabilities settled (24) (21)
Accretion 27 22
----------------------------------------------------------------------------
Asset retirement obligations at June 30 $ 692 $ 625
----------------------------------------------------------------------------
----------------------------------------------------------------------------

At June 30, 2008, the estimated total undiscounted inflation-adjusted
amount required to settle outstanding asset retirement obligations was
$5.2 billion. These obligations will be settled based on the useful lives
of the underlying assets, which currently extend an average of 30 years
into the future. This amount has been discounted using credit-adjusted
risk free rates ranging from 6.2% to 6.8%.

Note 12 Commitments and Contingencies

The Company has no material litigation other than various claims and
litigation arising in the normal course of business. While the outcome of
these matters is uncertain and there can be no assurance that such
matters will be resolved in the Company's favour, the Company does not
currently believe that the outcome of adverse decisions in any pending or
threatened proceedings related to these and other matters or any amount
which it may be required to pay by reason thereof would have a material
adverse impact on its financial position, results of operations or
liquidity.

Note 13 Share Capital

The Company's authorized share capital consists of an unlimited number of
no par value common and preferred shares.

Common Shares

Changes to issued common shares were as follows:
----------------------------------------------------------------------------

Six months ended June 30

2008 2007
----------------------------------------------------------------------------
Number of Number of
Shares Amount Shares
Amount--------------------------------------------------------------------------
-
Balance at beginning of year 848,960,310 $ 3,551 848,537,018 $ 3,533
Options exercised 183,000 8 311,592 14
----------------------------------------------------------------------------
Balance at June 30 849,143,310 $ 3,559 848,848,610 $ 3,547
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Stock Options

In accordance with the Company's stock option plan, common share options
may be granted to officers and certain other employees. The stock option
plan is a tandem plan that provides the stock option holder with the
right to exercise the option or surrender the option for a cash payment.
The exercise price of the option is equal to the weighted average trading
price of the Company's common shares during the five trading days prior
to the date of the award. When the option is surrendered for cash, the
cash payment is the difference between the weighted average trading price
of the Company's common shares on the trading day prior to the surrender
date and the exercise price of the option.

Under the terms of the original stock option plan, the options awarded
have a maximum term of five years and vest over three years on the basis
of one-third per year. Amendments to the Company's stock option plan in
2007 also provided for performance vesting of stock options. Performance
options granted may vest in up to one-third increments if the Company's
annual total shareholder return (stock price appreciation and cumulative
dividends on a reinvested basis) falls within certain percentile ranks
relative to its industry peer group. The ultimate number of performance
options that vest will depend upon the Company's performance measured
over three calendar years. If the Company's performance is below the
specified level compared with its industry peer group, the performance
options awarded will be forfeited. If the Company's performance is at or
above the specified level compared with its industry peer group, the
number of performance options exercisable shall be determined by the
Company's relative ranking.

The following tables cover all stock options granted by the Company for
the periods shown.

----------------------------------------------------------------------------
Six months ended June 30

2008 2007
----------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Exercise
Options Exercise Options Average
(thousands) Prices (thousands) Prices
----------------------------------------------------------------------------
Outstanding, beginning of
year 30,131 $ 37.18 11,656 $ 16.40
Granted 2,029 $ 40.62 25,211 $ 41.66
Exercised for common shares (183) $ 12.95 (311) $ 11.93
Surrendered for cash (3,355) $ 22.48 (3,712) $ 13.32
Forfeited (1,084) $ 41.40 (639) $ 38.79
----------------------------------------------------------------------------
Outstanding at June 30 27,538 $ 39.22 32,205 $ 36.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable at
June 30 7,479 $ 33.99 5,435 $ 12.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------

June 30, 2008

Outstanding Options Options Exercisable
----------------------------------------------------------------------------
Weighted Weighted Weighted
Number of Average Average Number of Average
Range of Exercise Options Exercise Contractual Options Exercise
Price (thousands) Prices Life (years) (thousands) Prices
----------------------------------------------------------------------------
$ 11.67 - $11.99 1,761 $ 11.74 1 1,761 $ 11.74
$ 12.00 - $17.99 80 $ 15.56 1 80 $ 15.56
$ 18.00 - $27.99 300 $ 25.92 2 53 $ 25.81
$ 28.00 - $36.99 681 $ 35.24 3 236 $ 35.19
$ 37.00 - $39.99 896 $ 39.45 4 58 $ 38.20
$ 40.00 - $40.99 2,441 $ 40.88 5 - $ -
$ 41.00 - $42.57 21,379 $ 41.69 4 5,291 $ 41.66
----------------------------------------------------------------------------
27,538 $ 39.22 4 7,479 $ 33.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Note 14 Employee Future Benefits

Total benefit costs recognized were as follows:
----------------------------------------------------------------------------

Three months Six months
ended June 30 ended June 30

2008 2007 2008 2007
----------------------------------------------------------------------------
Employer current service cost $ 8 $ 6 $ 15 $ 12
Interest cost 3 3 6 5
Expected return on plan assets (3) (3) (6) (5)
Amortization of net actuarial losses 1 1 2 2
----------------------------------------------------------------------------
$ 9 $ 7 $ 17 $ 14
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----------------------------------------------------------------------------

Note 15 Related Party Transactions

TransAlta Power, L.P. ("TAPLP") is under the indirect control of Husky's
principal shareholders. TAPLP is a 49.99% owner in TransAlta
Cogeneration, L.P. ("TACLP"), which is the Company's joint venture
partner for the Meridian cogeneration facility at Lloydminster. The
Company sells natural gas to the Meridian cogeneration facility and other
cogeneration facilities owned by TACLP. These natural gas sales are
related party transactions and have been measured at the exchange amount.
For the six months ended June 30, 2008, the total value of natural gas
sales to the Meridian and other cogeneration facilities owned by TACLP
was $64 million. At June 30, 2008, the total value of accounts receivable
related to these transactions was $8 million.

Note 16 Financial Instruments and Risk Management

Details of the Company's significant accounting policies for the
recognition and measurement of financial instruments and the basis for
which income and expense are recognized are disclosed in Note 3 of the
Company's 2007 consolidated financial statements.

Risk Management Overview

The Company is exposed to market risks related to the volatility of
commodity prices, foreign exchange rates and interest rates. In certain
instances, the Company uses derivative instruments to manage the
Company's exposure to these risks.

The Company employs risk management strategies and policies to ensure
that any exposures to risk are in compliance with the Company's business
objectives and risk tolerance levels. Risk management is ultimately
established by the Company's Board of Directors and is implemented by
senior management and monitored by the risk management function within
the Company.

Fair Value of Financial Instruments

The Company's financial instruments as at June 30, 2008 included cash and
cash equivalents, accounts receivable, contribution receivable, bank
operating loans, accounts payable and accrued liabilities, contribution
payable, long-term debt, the derivative portion of cash flow and fair
value hedges and freestanding and embedded derivatives.

The carrying value of cash and cash equivalents, accounts receivable,
bank operating loans, accounts payable and accrued liabilities
approximates their fair value due to the short-term maturity of these
investments.

At June 30, 2008, the carrying value of the contribution receivable and
contribution payable was $1.2 billion and $1.3 billion respectively. The
fair value of these financial instruments is not readily determinable due
to uncertainties regarding timing of the cash flows. Refer to Note 6,
"Joint Ventures."

The estimation of the fair value of commodity derivatives incorporates
forward prices and adjustments for quality or location. The estimation of
the fair value of interest rate and foreign currency derivatives
incorporates forward market prices, which are compared to quotes received
from financial institutions to ensure reasonability.

The fair value of long-term debt is the present value of future cash
flows associated with the debt. Market information such as treasury rates
and credit spreads is used to determine the appropriate discount rates.
These fair value determinations are compared to quotes received from
financial institutions to ensure reasonability. The estimated fair value
of long-term debt at the dates shown was:

----------------------------------------------------------------------------
June 30, 2008 December 31, 2007
Carrying Value Fair Value Carrying Value Fair Value
----------------------------------------------------------------------------
Long-term debt $ 2,129 $ 2,153 $ 2,814 $ 2,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Market Risk

Market risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk is comprised of foreign currency risk, interest rate risk and
other price risk, for example, commodity price risk. The objective of
market risk management is to manage and control market price exposures
within acceptable limits, while maximizing returns.

In certain instances, the Company uses derivative commodity instruments
to manage exposure to price volatility on a portion of its oil and gas
production and firm commitments for the purchase or sale of crude oil and
natural gas.

The Company's results are affected by the exchange rate between the
Canadian and U.S. dollar. The majority of the Company's revenues are
received in U.S. dollars or from the sale of oil and gas commodities that
receive prices determined by reference to U.S. benchmark prices. An
increase in the value of the Canadian dollar relative to the U.S. dollar
will decrease the revenues received from the sale of oil and gas
commodities. Correspondingly, a decrease in the value of the Canadian
dollar relative to the U.S. dollar will increase the revenues received
from the sale of oil and gas commodities. The majority of the Company's
expenditures are in Canadian dollars.

A change in the value of the Canadian dollar against the U.S. dollar will
also result in an increase or decrease in the Company's U.S. dollar
denominated debt, as expressed in Canadian dollars, as well as the
related interest expense. In order to mitigate the Company's exposure to
long-term debt affected by the U.S./Canadian dollar exchange rate, the
Company has entered into cash flow hedges using cross currency debt
swaps. In addition, a portion of our U.S. dollar denominated debt has
been designated as a hedge of a net investment in a self-sustaining
foreign operation and the unrealized foreign exchange gain is recorded in
Other Comprehensive Income.

To mitigate risk related to interest rates, the Company enters into fair
value hedges using interest rate swaps. The Company's objectives,
processes and policies for managing market risk have not changed from the
previous year.

Commodity Price Risk Management

Natural Gas Contracts

At June 30, 2008, the Company had the following third party offsetting
physical purchase and sale natural gas contracts, which met the
definition of a derivative instrument:

----------------------------------------------------------------------------

Volumes
(mmcf) Fair Value
----------------------------------------------------------------------------
Physical purchase contracts 30,972 $ 19
Physical sale contracts (30,972) $ (18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

These contracts have been recorded at their fair value in accounts
receivable and the resulting unrealized gain or loss has been recorded in
other expenses in the consolidated statement of earnings.

Interest Rate Risk Management

At June 30, 2008, the Company had entered into a fair value hedge using
interest rate swap arrangements whereby the fixed interest rate coupon on
the medium-term notes was swapped to floating rates with the following
terms:

----------------------------------------------------------------------------

Swap Rate
Debt Amount Swap Maturity (percent) Fair Value
----------------------------------------------------------------------------
6.95% medium-term notes $ 200 July 14, 2009 CDOR + 175 bps $ 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

This contract has been recorded at fair value in other assets. During
the six months ended June 30, 2008, the Company recognized a loss of less
than $1 million (2007 - gain of $1 million) on the interest rate swap
arrangements.

Embedded Derivative

The Company entered into a contract with a Norwegian-based company for
drilling services offshore China. The contract currency is U.S. dollars,
which is not the functional currency of either transacting party. As a
result, this contract has been identified as containing an embedded
derivative requiring bifurcation and separate accounting treatment at
fair value. This embedded derivative has been recorded at fair value in
accounts receivable and other assets and the resulting unrealized loss
has been recorded in other expenses in the consolidated statement of
earnings. At June 30, 2008, the fair value of the embedded derivative was
$84 million (December 31, 2007 - $101 million). In the first six months
of 2008, the impact was an unrealized loss on the embedded derivative of
$17 million.

Foreign Currency Risk Management

The Company manages its exposure to foreign exchange fluctuations by
balancing the U.S. dollar denominated cash flows with U.S. dollar
denominated borrowings and other financial instruments. Husky utilizes
spot and forward sales to convert cash flows to or from U.S. or Canadian
currency.

At June 30, 2008, the Company had a cash flow hedge using the following
cross currency debt swaps:

----------------------------------------------------------------------------

Canadian Interest Rate
Debt Swap Amount Equivalent Swap Maturity (percent) Fair Value
----------------------------------------------------------------------------
6.25% notes U.S. $ 150 $ 212 June 15, 2012 7.41 $ (73)
6.25% notes U.S. $ 75 $ 90 June 15, 2012 5.65 $ (13)
6.25% notes U.S. $ 50 $ 59 June 15, 2012 5.67 $ (7)
6.25% notes U.S. $ 75 $ 88 June 15, 2012 5.61 $ (10)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

These contracts have been recorded at fair value in other long-term
liabilities. The portion of the fair value of the derivative related to
foreign exchange losses has been recorded in earnings to offset the
foreign exchange on the translation of the underlying debt. The remaining
loss of $8 million, net of tax of $4 million, has been included in other
comprehensive income. At June 30, 2008, the balance in accumulated other
comprehensive income was $9 million, net of tax of $4 million. For the
six months ended June 30, 2008, the Company recognized a foreign exchange
gain of $11 million (2007 - loss of $4 million) on the cross currency
debt swaps.

The Company enters into short-dated foreign exchange contracts to fix the
exchange rate for conversion of U.S. dollars to Canadian dollars. During
the first six months of 2008, the impact of these contracts was a loss of
$1 million (2007 - gain of $2 million).

The Company entered into forward purchases of U.S. dollars to partially
offset the fluctuations in foreign exchange related to the contract for
drilling services offshore China, which contains an embedded derivative.
At June 30, 2008, the following foreign exchange transactions had been
entered into:

----------------------------------------------------------------------------
Forward Canadian Fair
Date Purchases Equivalent Value
----------------------------------------------------------------------------
October 5, 2007 U.S. $ 119 $ 117 $ 4
October 11, 2007 U.S. $ 119 $ 116 $ 5
October 29, 2007 U.S. $ 119 $ 115 $ 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

These forward contracts have been recorded at fair value in accounts
receivable and other assets and the resulting gain has been recorded in
other expenses in the consolidated statement of earnings. During the
first six months of 2008, the impact was a gain of $8 million.

Effective July 1, 2007, the Company's U.S. $1.5 billion of debt financing
related to the Lima acquisition was designated as a hedge of the
Company's net investment in the U.S. refining and marketing operations,
which are considered self-sustaining. During the second quarter of 2008,
the Company repaid its bridge financing of U.S. $750 million. As a
result, the Company's net investment hedge is limited to the remaining
U.S. $750 million. As at June 30, 2008, the unrealized foreign exchange
loss of $40 million, net of tax of $7 million, arising from the
translation of the debt is recorded in other comprehensive income.

Sensitivity Analysis

This sensitivity analysis has been calculated by increasing or decreasing
the interest rate or foreign currency exchange rate, as appropriate, in
the fair value methodologies described in the "Fair Value of Financial
Instruments" section of this note. These sensitivities represent the
effect resulting from changing the relevant rates with all other
variables held constant and have been applied only to financial
instruments. The Company's process for determining these sensitivities
has not changed from the previous quarter. The Company is exposed to
interest rate risk on its interest rate swaps. As at June 30, 2008, had
interest rates been 50 basis points higher or lower and assuming all
other variables remained constant, the impact to fair value would have
been less than $1 million. The impact to net earnings would have been nil.

The Company is exposed to interest rate and foreign currency risk on its
cross currency debt swaps. Had the Canadian dollar been 1% stronger
versus the U.S. dollar and assuming all other variables remained
constant, the impact to other comprehensive income would have been $6
million lower. As at June 30, 2008, had the Canadian dollar been 1%
weaker versus the U.S. dollar and assuming all other variables remained
constant, the impact to other comprehensive income would have been $4
million higher. As at June 30, 2008, had the interest rates been 50 basis
points higher and assuming all other variables remained constant, the
impact to other comprehensive income would have been $2 million higher.
An equal and offsetting impact would have occurred had the interest rates
been 50 basis points lower and assuming all other variables remained
constant.

The Company is exposed to foreign currency risk on its embedded
derivative and its forward purchases of U.S. dollars to partially offset
the fluctuations in foreign exchange related to the embedded derivative.
As at June 30, 2008, had the Canadian dollar been 1% stronger relative to
the U.S. dollar and assuming all other variables remained constant, the
impact to net earnings would have been $6 million higher for the embedded
derivative and $4 million lower for the forward purchases of U.S.
dollars. Equal and offsetting impacts would have occurred had the
Canadian dollar been 1% weaker relative to the U.S. dollar and assuming
all other variables remained constant.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they become due. The Company's processes for
managing liquidity risk include ensuring, to the extent possible, that it
will have sufficient liquidity to meet its liabilities when they become
due. The Company prepares annual capital expenditure budgets which are
monitored and are updated as required. In addition, the Company requires
authorizations for expenditures on projects to assist with the management
of capital.

Since the Company operates in the upstream oil and gas industry, it
requires sufficient cash to fund capital programs necessary to maintain
or increase production and develop reserves, to acquire strategic oil and
gas assets, to repay maturing debt and to pay dividends. The Company's
upstream capital programs are funded principally by cash provided from
operating activities. However, during times of low oil and gas prices, a
portion of capital programs can generally be deferred. However, due to
the long cycle times and the importance to future cash flow in
maintaining the Company's production, it may be necessary to utilize
alternative sources of capital to continue the Company's strategic
investment plan during periods of low commodity prices. As a result, the
Company frequently evaluates the options available with respect to
sources of long and short-term capital resources. Occasionally, the
Company will hedge a portion of its production to protect cash flow in
the event of commodity price declines. In addition, the Company has
access to a revolving syndicated credit facility which allows the Company
to borrow money from a group of banks on an unsecured basis.

The following are the contractual maturities of financial liabilities as
at June 30, 2008:

----------------------------------------------------------------------------

1 to 2 to
Less than less than less than
Financial Liability 1 Year 2 Years 5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 2,945 $ - $ - $ -
Cross currency swaps - - 447 -
Long-term debt and interest on
fixed rate debt 361 317 724 2,298
Other long-term liabilities 5 - - -
----------------------------------------------------------------------------
Total $ 3,311 $ 317 1,171 $ 2,298
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company's contribution payable to the joint venture with BP (refer
to Note 6) is payable between June 30, 2008 and December 31, 2015 with
the final balance due and payable by December 31, 2015.

The Company's objectives, processes and policies for managing liquidity
risk have not changed from the previous year.

Credit Risk

Credit risk represents the financial loss that the Company would suffer
if the Company's counterparties to a financial instrument, in owing an
amount to the Company, fail to meet or discharge their obligation to the
Company. The Company's accounts receivables are predominantly with
customers in the energy industry and are subject to normal industry
credit risks. The Company's policy to mitigate credit risk is to
primarily deal with major financial institutions and investment grade
rated entities. The Company did not have any customers that constituted
more than 10% of total sales and operating revenues during the second
quarter of 2008.

Cash and cash equivalents include cash bank balances and short-term
deposits maturing in less than 30 days. The Company manages the credit
exposure related to short-term investments by monitoring exposures daily
on a per issuer basis relative to predefined investment limits.

The carrying amount of accounts receivable and cash and cash equivalents
represents the maximum credit exposure.

The Company considers its accounts receivable excluding income taxes
receivable and doubtful accounts to be aged as follows:
----------------------------------------------------------------------------

Aging June 30, 2008
----------------------------------------------------------------------------
Current $ 1,939
Past due (1 - 30 days) 217
Past due (31 - 60 days) 6
Past due (61 - 90 days) 4
Past due (more than 90 days) 17
----------------------------------------------------------------------------
Total $ 2,183
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The movement in the Company's allowance for doubtful accounts for the first
six months of 2008 was as follows:
----------------------------------------------------------------------------
Balance at January 1, 2008 $ 10
Provisions and revisions 2
----------------------------------------------------------------------------
Balance at June 30, 2008 $ 12
----------------------------------------------------------------------------
----------------------------------------------------------------------------

For the first six months of 2008, the Company wrote off $1 million of
uncollectible receivables.

The Company's objectives, processes and policies for managing credit risk
have not changed from the previous year.

Sale of Accounts Receivable

The Company has a securitization program to sell, on a revolving basis,
accounts receivable to a third party up to $350 million. As at June 30,
2008, no accounts receivable had been sold under the program (December
31, 2007 - nil).

Held-for-Trading Financial Liabilities

The Company's cross currency swaps have been designated as a cash flow
hedge and the derivative component of the hedge meets the definition of a
held-for-trading financial liability. The cross currency swap
counterparties' credit profiles have not materially changed since the
past year or since inception. As a result, the amount of change during
the period and cumulatively in the fair value of the cross currency swaps
has not been materially impacted by changes resulting from credit risk.
At June 30, 2008, the amount the Company would be contractually required
to pay under the cross currency swaps at maturity was $344 million higher
(December 31, 2007 - $341 million higher) than their carrying amount.

Note 17 Capital Disclosures

The Company's objectives when managing capital are: (i) to maintain a
flexible capital structure, which optimizes the cost of capital at
acceptable risk; and (ii) to maintain investor, creditor and market
confidence to sustain the future development of the business.

The Company manages its capital structure and makes adjustments to it in
light of changes in economic conditions and the risk characteristics of
our underlying assets. The Company considers its capital structure to
include shareholders' equity, debt and working capital. To maintain or
adjust the capital structure, the Company may from time to time, issue
shares, raise debt and/or adjust its capital spending to manage its
current and projected debt levels.

The Company monitors capital based on the current and projected ratios of
debt to cash flow and debt to capital employed. The Company's objective
is to maintain a debt to cash flow from operations ratio of less than two
times. The ratio may increase at certain times as a result of
acquisitions. To facilitate the management of this ratio, the Company
prepares annual budgets, which are updated depending on varying factors
such as general market conditions and successful capital deployment. The
annual budget is approved by the Board of Directors. The Company's share
capital is not subject to external restrictions; however the bilateral
credit facilities and the syndicated credit facility include a debt to
cash flow covenant. The Company was fully compliant with this covenant at
June 30, 2008.

There were no changes in the Company's approach to capital management
from the previous year.

Husky Energy Inc. will host a conference call for analysts and investors
on Thursday, July 24, 2008 at 5:15 p.m. Eastern time to discuss Husky's
second quarter results. To participate please dial 1-800-319-4610
beginning at 5:05 p.m. Eastern time.

Mr. John C.S. Lau, President & Chief Executive Officer, and other
officers will be participating in the call.

A live audio webcast of the conference call will be available via Husky's
website, www.huskyenergy.com under Investor Relations. The webcast will
be archived for approximately 90 days.

Media are invited to listen to the conference call

- Dial 1-800-597-1419 beginning at 5:05 p.m. (Eastern time)

A recording of the call will be available at approximately 7:30 p.m.
(Eastern time)

- Dial 1-800-319-6413 (dial reservation # 2658)

The Postview will be available until October 24, 2008.

Contacts:
Husky Energy Inc.
Patrick Aherne
Manager, Investor Relations
(403) 298-6817

Husky Energy Inc.
707 - 8th Avenue S.W., Box 6525, Station D
Calgary, Alberta, Canada T2P 3G7
(403) 298-6111
(403) 298-6515 (FAX)
Email: Investor.Relations@huskyenergy.com
Website: www.huskyenergy.com

Copyright 2008, Market Wire, All rights reserved.

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