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FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy Reports 2007 Second Quarter Results

Jul 18, 2007 - 05:24 ET

CALGARY, ALBERTA--(Marketwire - July 18, 2007) - Husky Energy Inc. (TSX:HSE) reported net earnings of $721 million or $0.85 per share (diluted) in the second quarter of 2007 compared with $978 million or $1.15 per share (diluted) in the same quarter of 2006. Net earnings for the second quarter of 2007 included a non-recurring benefit due to tax rate reductions of $30 million or $0.04 per share (diluted) compared with $328 million or $0.39 per share (diluted) in the second quarter of 2006. Excluding the non-recurring tax benefits, the second quarter net earnings were $691 million for 2007 compared with $650 million for 2006.

Cash flow from operations in the second quarter was $1.3 billion or $1.48 per share (diluted), a 14% increase compared with $1.1 billion or $1.30 per share (diluted) in the same quarter of 2006. Sales and operating revenues, net of royalties, were $3.2 billion in the second quarter of 2007, up 4% compared with $3.0 billion in the second quarter of 2006.

In the second quarter of 2007, total production averaged 379,100 barrels of oil equivalent per day, a 10% increase over 344,000 barrels of oil equivalent per day in the second quarter of 2006. Total crude oil and natural gas liquids production was 276,500 barrels per day and natural gas production was 615.7 million cubic feet per day.

"Husky achieved strong financial performance for the quarter despite the continuing weakness in the U.S. dollar," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "In July, the acquisition of the Lima refinery in Ohio, which represents a significant step in Husky's strategy of integrated heavy oil and bitumen development, will contribute positively to Husky's earnings and cash flow."

Subsequent to the end of the second quarter, Husky completed the acquisition of the refinery in Lima, Ohio from Valero Energy Corporation. The purchase price was U.S. $1.9 billion, plus net working capital. Various options will be examined to enhance the value of this refinery including opportunities to integrate Husky's heavy oil and oil sands production.

The Tucker Oil Sands project, which is expected to reach 30,000 barrels per day by the end of 2008, completed its initial warm-up phase and is ramping up SAGD production.

The Sunrise Oil Sands project continues to progress on schedule with the completion of the front-end engineering design work planned for the fourth quarter of 2007.

Production at the White Rose oil field in the second quarter reached approximately 136,000 barrels per day and averaged 90,300 barrels per day net to Husky. A seventh production well has been completed, bringing total reservoir capacity to 140,000 barrels per day. The field is currently undergoing a 16-day planned turnaround. Drilling of the C-30 delineation well in the western section of the White Rose field commenced in June and is continuing.

At the Lloydminster Upgrader, a scheduled 40-day turnaround has been completed. The majority of the debottleneck projects were completed during the turnaround. Throughput capacity of 82,000 barrels per day will be realized in the fourth quarter of 2007 pending completion of remaining work items. Front-end engineering design for a potential expansion of the Upgrader continues and is expected to be completed in the fourth quarter of 2007.

With regards to exploration, Husky was awarded an 87.5% interest in two exploration licences offshore Greenland. The two blocks cover an area of 21,067 square kilometres and are located approximately 120 kilometres offshore the west coast of Disko Island.

Internationally, Husky has commenced a seismic program in the South China Sea over Block 29/26 that contains the Liwan natural gas discovery and the adjacent Block 29/06. The program will evaluate exploration leads for future drilling locations. Delineation of the Liwan discovery will commence in the second half of 2008 upon the arrival of the West Hercules deep water drilling rig.

In Minnedosa, construction of the new ethanol production facility is currently 68% complete with commissioning expected in the fourth quarter of 2007.

Husky's financial position remains strong. At June 30, 2007, Husky's debt to cash flow ratio was 0.3 to 1 and debt to capital was 12%.

For the first six months of 2007, Husky's net earnings were $1.4 billion or $1.61 per share (diluted), compared with $1.5 billion or $1.77 per share (diluted) for the same period in 2006. Cash flow from operations for the first six months of 2007 was $2.6 billion or $3.04 per share (diluted), compared with $2.1 billion or $2.44 per share (diluted) for the same period in 2006.

Production in the first six months of 2007 was 384,600 barrels of oil equivalent per day, compared with 348,700 barrels of oil equivalent per day in the same period in 2006. Total crude oil and natural gas liquids production was 279,900 barrels per day, compared with 235,500 barrels per day during the first six months of 2006. Natural gas production was 627.8 million cubic feet per day, compared with 679.0 million cubic feet per day in the first six months of 2006.

Our current forecast for crude oil production in 2007 remains within our guidance range. Our current forecast for natural gas production in 2007 will likely be less than 670 million cubic feet per day as a result of the redeployment of capital, delayed natural gas well tie-ins and capital project delays.

MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") JULY 18, 2007

TABLE OF CONTENTS

1.0 Quarterly Financial Results

2.0 Core Business Strategy

3.0 Capability to Deliver Results

4.0 Results of Operations

5.0 Liquidity and Capital Resources

6.0 Risks and Risk Management

7.0 Critical Accounting Estimates

8.0 Changes in Accounting Policies

9.0 Outstanding Share Data

10.0 Non-GAAP Measures

11.0 Reader Advisories

12.0 Forward-looking Statements

1.0 QUARTERLY FINANCIAL RESULTS

Husky's net earnings for the second quarter of 2007 were $721 million, down $257 million or 26% compared with the second quarter of 2006.

Second Quarter

The decrease in net earnings in the second quarter of 2007 was mainly related to a variance of $290 million in income taxes, primarily from a future tax recovery recorded in the second quarter of 2006. In addition, stock-based compensation was $28 million higher in the second quarter of 2007 compared with the second quarter of 2006.

Earnings before income taxes were $992 million in the second quarter of 2007 compared with $959 million in the second quarter of 2006, an increase of $33 million. The increase in earnings before income taxes includes higher earnings from the Upstream and Refined Products segments partially offset by lower earnings from the Midstream segment. During the second quarter of 2007, the upgrader at Lloydminster underwent a 49 day turnaround and as a result synthetic crude sales volume was 42% lower than the corresponding quarter in 2006.

Cash flow from operations was $1.3 billion in the second quarter of 2007 compared with $1.1 billion in the second quarter of 2006.

Six Months

Husky's net earnings for the first six months of 2007 were $1.4 billion compared with $1.5 billion during the first six months of 2006. The decrease in net earnings in the first six months of 2007 resulted primarily from the tax recovery recorded in 2006.

Earnings before income taxes were $1.9 billion in the first six months of 2007 compared with $1.7 billion in the first six months of 2006. The increase in earnings before income taxes in 2007 resulted from the same factors that affected the second quarter.

Cash flow from operations was $2.6 billion in the first six months of 2007 compared with $2.1 billion in the first six months of 2006.



----------------------------------------------------------------------------
Financial Summary Three months Six months
ended June 30 ended June 30
(millions of dollars,
except per share amounts and ratios) 2007 2006 2007 2006
----------------------------------------------------------------------------
Segmented earnings
Upstream $ 636 $ 822 $ 1,216 $ 1,234
Midstream 77 140 188 290
Refined Products 53 52 73 68
Corporate and eliminations (45) (36) (106) (90)
----------------------------------------------------------------------------
Net earnings $ 721 $ 978 $ 1,371 $ 1,502
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Per share - Basic and diluted (1) $ 0.85 $ 1.15 $ 1.61 $ 1.77
Cash flow from operations 1,257 1,103 2,581 2,070
Per share - Basic and diluted (1) 1.48 1.30 3.04 2.44
Ordinary quarterly dividend per
common share (1) 0.25 0.125 0.50 0.25
Special dividend per common share (1) - - 0.25 -
Total assets 17,969 16,328 17,969 16,328
Total long-term debt including
current portion 1,423 1,722 1,423 1,722
Return on equity (2) (percent) 27.1 34.8 27.1 34.8
Return on average capital employed (2)
(percent) 23.8 28.2 23.8 28.2
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----------------------------------------------------------------------------

(1) Reflects a two-for-one share split on June 27, 2007, which has been
applied retroactively. Refer to Note 9 to the Consolidated Financial
Statements.

(2) Calculated for the 12 months ended for the dates shown.

 


2.0 CORE BUSINESS STRATEGY

Our core business strategy was presented in our 2006 annual Management's Discussion and Analysis, which is available from the Canadian Securities Administrators' web site, www.sedar.com, the U.S. Securities and Exchange Commission's web site, www.sec.gov or our web site www.huskyenergy.ca.

In summary, our strategy is to continue to exploit our conventional oil and gas asset base in Western Canada while expanding into new areas with large scale growth projects. Our plans include projects in the Alberta oil sands, the basins off the East Coast of Canada, the central Mackenzie River Valley, the South China Sea, Madura Strait and the East Java Sea in Indonesia. Our plans for the Midstream and Refined Products segments involve enhancing performance and capturing new value throughout the value chain by further integrating existing operations and the Lima refinery, optimizing our plant operations and expanding plant and infrastructure operations where warranted.

3.0 CAPABILITY TO DELIVER RESULTS

Our current capacity to deliver results was also provided in our recently filed MD&A and in our Annual Information Form that are available from www.sedar.com and www.sec.gov. In order to deliver competitive results, we must continually identify and develop an inventory of projects and opportunities that will provide a satisfactory return on investment. The major projects that are currently at varying stages of development are discussed below.

3.1 UPSTREAM

WHITE ROSE OIL FIELD

At the end of the first quarter of 2007, the governments of Canada and Newfoundland and Labrador together with the Canada-Newfoundland and Labrador Offshore Petroleum Board ("C-NLOPB") approved our application to increase production at the White Rose oil field to 50 mmbbls annually, with a maximum 140 mbbls/day, subject to several conditions that relate to safety, conservation and production control.

In early June 2007, the seventh production well was completed. The completion of this well has increased reservoir production capacity to the approved 140 mbbls/day. Allowing for downtime associated with maintenance, regulatory inspection, drilling rig movements and well tie-in activities, the White Rose oil field is expected to produce between 120 mbbls/day and 125 mbbls/day (87 mbbls/day to 91 mbbls/day Husky's share) on an annual average basis. One additional gas injection well remains to be drilled in the third quarter of 2007. The completion of this well will conclude our 18 well development plan for the South Avalon portion of the White Rose oil field.

SEAROSE FPSO TIE-BACK PROGRAM

In June 2007, glory hole excavation into the seabed commenced at what will become the North Amethyst drill centre using the suction hopper dredge vessel, Vasco da Gama. The North Amethyst glory hole is currently 65% complete. Front-end engineering design studies to support the tie-back of various satellite reservoirs and required facility modifications are, in total, approximately 80% complete.

The South White Rose Extension development plan amendment is currently under review by the C-NLOPB. We also plan to submit applications for our proposed tie-backs at North Amethyst and West White Rose in the coming months.

EAST COAST CANADA EXPLORATION AND WHITE ROSE DELINEATION

We are currently drilling the C-30 delineation well, which will provide additional data on resources discovered in 2006 in the western section of the White Rose field. A side-track of the C-30 well is planned to further evaluate reservoir quality and we intend to conduct a drill stem test to determine productivity in this part of the reservoir.

In addition, evaluation of 3-D seismic data acquired over Exploration Licences 1067 and 1011 is progressing.

TUCKER OIL SANDS PROJECT

During the second quarter, we continued to steam the reservoir at Tucker through the well pairs, both the production and injection wells. At the end of the second quarter, all of the well pairs had been switched to steam-assisted gravity drainage ("SAGD") production, steaming through the injector of each pair. Initially, production has a high steam/oil ratio, which is expected to improve in the coming months as production ramps up.

SUNRISE OIL SANDS PROJECT

The front-end engineering design of the Sunrise Oil Sands project is continuing and is approximately 67% complete. This work is expected to be completed by the fourth quarter of 2007. The first phase of the project will have a design rate of 60 mbbls/day of bitumen sales, and will ultimately be developed by successive phases to a production plateau of 200 mbbls/day.

In the field, early site preparation work will be completed this fall, expansion of the drilling camp and commencement of accommodations for construction workers for the second half of 2008. The winter 2008 drilling program is in the planning phase; currently, 50 stratigraphic test and observation well locations are being surveyed and licensed. Regulatory application for the project water supply was submitted in early spring and work on water disposal logistics continues. We are also continuing to discuss and plan the general area's infrastructure needs with various industry participants.

CARIBOU

At Caribou, we completed geological mapping and integration with the 3-D seismic acquired earlier in 2007. Geological modeling and simulation studies continued in the second quarter. Discussions and negotiations are continuing with regulatory authorities and various stakeholder groups on the Energy and Utilities Board and Alberta Environment application. Front-end engineering has commenced and is expected to be completed in the fourth quarter of 2007.

SALESKI

At Saleski, geological mapping and cross sections are being assembled for stratigraphic drilling locations. An initial survey is underway to determine the appropriate route for an all season access road. In addition, we are examining the technical merits of various production processes for Saleski.

NORTHWEST TERRITORIES EXPLORATION

In May 2007, we were awarded EL 443, which covers 224,886 acres adjacent to our existing landholdings in the Central Mackenzie Valley. In respect of our oil and gas exploration prospects at Summit Creek and Stewart Lake, we are currently evaluating seismic data acquired in September 2006. We plan to undertake a drilling program in the winter of 2007/2008 to further appraise these discoveries.

CHINA EXPLORATION

During the second quarter of 2007, we began to acquire seismic data in the South China Sea over Block 29/26, which contains the Liwan natural gas discovery, and the adjacent Block 29/06. The program will cover a total of 766,000 acres and will evaluate exploration leads for future drilling locations. Proposed delineation well locations are currently being evaluated based on 3-D seismic data acquired earlier. Delineation of Liwan is planned to commence in the second half of 2008 upon the arrival of the West Hercules deep water drilling rig, which is currently being constructed. At June 30, 2007, the West Hercules was 64% complete. We have secured the West Hercules for three years.

On June 27, 2007, we entered into an agreement for the use of a jack-up rig for shallow water drilling. The rig will be available in October 2007 and will be deployed in the South China Sea on Block 23/15. We will continue to pursue securing an additional rig suitable for the remainder of our shallow water exploration program.

INDONESIA NATURAL GAS DEVELOPMENT AND EXPLORATION

In Indonesia, our negotiations continued with BPMIGAS and other players in order to expedite the approval process. Our amended development plan for the BD natural gas and condensate field in the Madura Strait was submitted to BPMIGAS for their approval. Environmental impact studies were started during the second quarter.

We are currently assessing bids to acquire 3-D seismic data on our recently awarded exploration block, East Bawean II.

OFFSHORE GREENLAND

In June 2007, we were awarded two adjacent exploration licences offshore Greenland. Block 5 (2007-22) is 2.5 million acres and Block 7 (2007-24) is 2.7 million acres. Both blocks are west of Disko Island off the west coast of Greenland in less than 500 metres of water. We have committed to spend U.S. $10.6 million on Block 5 and U.S. $28 million on Block 7 over the next three years. This work commitment includes the acquisition of 7,000 kilometres of 2-D seismic and 1,000 kilometres of 3-D seismic.

3.2 MIDSTREAM

LLOYDMINSTER TO HARDISTY PIPELINE EXPANSION

Construction of the second phase of our pipeline expansion is approximately 10% complete and is on schedule to be finished by the fourth quarter of 2007.

LLOYDMINSTER UPGRADER EXPANSION

The front-end engineering design for the potential expansion of the Lloydminster Upgrader has reached approximately 91% completion. We anticipate a decision on whether to proceed with the expansion in the second half of 2007.

3.3 REFINED PRODUCTS

ACQUISITION OF THE LIMA OHIO REFINERY

In May 2007, we announced the pending acquisition of the Valero refinery at Lima, Ohio, located between Dayton and Toledo. The acquisition closed on July 3, 2007 for a purchase price of U.S. $1.9 billion, plus net working capital. An additional U.S. $540 million was paid for feedstock and product inventory.

The Lima refinery has a nameplate capacity of 165 mbbls/day and processes primarily sweet crude oil and limited amounts of sour heavy crude oil. The refinery produces conventional gasoline, reformulated gasoline for oxygenate blending, diesel, jet fuels and petrochemicals. We intend to review options in respect of reconfiguring and expanding this refinery to process heavy crude oil and bitumen as primary feedstocks.

This acquisition was financed with a short-term bridge facility and existing credit facilities.

MINNEDOSA ETHANOL PLANT

At Minnedosa, the construction of the new ethanol plant is 68% complete. We expect to commission the plant and achieve full operation in the fourth quarter of 2007.

4.0 RESULTS OF OPERATIONS

The following table discloses earnings by major business segment and includes corporate expenses and intersegment profit elimination amounts, the aggregate of which is equal to consolidated net earnings. (Please visit www.huskyenergy.ca to view the table.)



4.1 UPSTREAM
----------------------------------------------------------------------------
Upstream Earnings Summary Three months Six months
ended June 30 ended June 30

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross revenues $ 1,828 $ 1,658 $ 3,591 $ 3,151
Royalties 235 207 433 413
----------------------------------------------------------------------------
Net revenues 1,593 1,451 3,158 2,738
Operating and administration
expenses 344 308 667 619
Depletion, depreciation and
amortization 407 354 806 705
Other (49) - (49) -
Income taxes 255 (33) 518 180
----------------------------------------------------------------------------
Earnings $ 636 $ 822 $ 1,216 $ 1,234
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THE UPSTREAM BUSINESS ENVIRONMENT

Commodity Prices

The average prices we realized during the second quarter and first six
months of 2007 compared with the second quarter and first six months of 2006
are illustrated below.

----------------------------------------------------------------------------
Average Sales Prices Three months Six months
ended June 30 ended June 30

2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil ($/bbl)
Light crude oil & NGL $ 72.28 $ 73.74 $ 68.28 $ 70.35
Medium crude oil 48.15 58.42 47.26 48.29
Heavy crude oil 38.41 48.12 38.03 37.28
Total average 56.99 60.18 54.68 52.54
Natural Gas ($/mcf)
Average 6.91 5.95 6.92 7.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The prices received for our crude oil production are determined by global economic factors. The grade of our crude oil also affects the price we receive. The economics of refining crude oil into finished products such as gasoline and distillates favours light sweet crude oil over heavy sour crude oil because the light sweet feedstock yields a higher proportion of more valuable motor fuels, such as gasoline, without the need to incur the additional costs of removing residual asphaltenes and sulphur.

Natural gas prices are not affected as much by global economics, but by local supply and demand because transportation of natural gas is limited to pipelines.

Our Upstream results are significantly influenced by commodity prices. The following table shows certain select average quarterly market benchmark prices:



----------------------------------------------------------------------------
Average Benchmark Prices
and U.S. Exchange Rate Three months ended

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

2007 2007 2006 2006 2006
----------------------------------------------------------------------------
WTI crude oil(1) (U.S. $/bbl) 65.03 58.16 60.21 70.48 70.70
Brent crude oil(2) (U.S. $/bbl) 68.76 57.75 59.68 69.49 69.62
Canadian light crude
0.3% sulphur ($/bbl) 72.61 67.76 65.12 79.65 78.97
Lloyd heavy crude
oil @ Lloydminster ($/bbl) 39.02 38.25 35.24 49.61 48.65
NYMEX natural
gas(1) (U.S. $/mmbtu) 7.55 6.77 6.56 6.58 6.79
NIT natural gas ($/GJ) 6.99 7.07 6.03 5.72 5.95
WTI/Lloyd crude blend
differential (U.S. $/bbl) 20.36 17.32 21.75 19.24 17.99
U.S./Canadian dollar
exchange rate (U.S. $) 0.911 0.854 0.878 0.892 0.891
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.

 


Crude Oil

The following graph illustrates the relative changes over several quarters in the realized prices of our three main crude oil categories expressed in U.S. dollars and West Texas Intermediate ("WTI"), the main benchmark crude oil. (Please visit www.huskyenergy.ca to view the chart.)

The majority of our crude oil production is marketed in North America and the primary benchmark crude oil in North America is WTI. During the second quarter of 2007, WTI trended up from the first quarter of 2007 but average WTI prices were lower than in the second quarter of 2006. During the second quarter of 2007, WTI prices came under pressure whereas other benchmark crude oil categories, such as Brent, traded at a premium to the North American standard crude. Stocks of WTI, which is normally a clear market indicator, were high as a result of higher Canadian crude oil exported to the United States and higher than usual maintenance and outages of refineries that would normally take WTI. Brent on the other hand, was the best market indicator as it increased in the second quarter of 2007 and averaged at a similar level to the second quarter of 2006. At the end of the second quarter of 2007, crude oil prices were spiking in reaction to production disruption in Nigeria.

Natural Gas

The following graph illustrates the relative changes over several quarters in our natural gas price realized compared with two major benchmark prices. (Please visit www.huskyenergy.ca to view the chart.)

Since the beginning of 2006, moderate weather in the major North American market areas has resulted in lower heating and cooling demand and therefore higher natural gas supplies. These events have kept natural gas prices on the low side. The NYMEX price for near month settlement averaged U.S. $7.55/mmbtu during the second quarter of 2007.

Revenue

Second Quarter

(Please visit www.huskyenergy.ca to view the Net Revenue Variance Analysis chart.)

During the second quarter of 2007, our upstream net revenues were $1.6 billion, compared with $1.5 billion in the second quarter of 2006.

In the second quarter of 2007, Western Canada was the source of 57% of our crude oil and 100% of our natural gas production resulting in 56% of upstream revenue before royalties. East Coast Canada contributed 38% of our crude oil production, 79% of our light crude oil production and resulted in 39% of upstream revenue before royalties. China contributed 5% of revenue.

In the second quarter of 2006, Western Canada was the source of 71% of our crude oil and 100% of our natural gas production resulting in 71% of upstream revenue before royalties. East Coast Canada contributed 24% of our crude oil production, 64% of our light crude oil production and resulted in 24% of upstream revenue before royalties. China contributed 5% of revenue.

On April 11, 2007, we closed a transaction to dispose of several properties located mainly in northwest Alberta with production of approximately 5,200 boe/day.

Six Months

(Please visit www.huskyenergy.ca to view the Net Revenue Variance Analysis chart.)

During the first six months of 2007, our upstream net revenues were $3.2 billion, compared with $2.7 billion in the corresponding period of 2006.

In the first six months of 2007, Western Canada was the source of 58% of our crude oil and 100% of our natural gas production resulting in 58% of upstream revenue before royalties. East Coast Canada contributed 37% of our crude oil production, 77% of our light crude oil production and resulted in 37% of upstream revenue before royalties. China contributed 5% of revenue.

In the first half of 2006, Western Canada was the source of 71% of our crude oil and 100% of our natural gas production resulting in 71% of upstream revenue before royalties. East Coast Canada contributed 24% of our crude oil production, 63% of our light crude oil production and resulted in 24% of upstream revenue before royalties. China contributed 5% of revenue.



----------------------------------------------------------------------------
Effective Royalty Rates

Royalties per
unit of production
and percentage of Three months ended June 30 Six months ended June 30
upstream gross
revenues 2007 2006 2007 2006
----------------------------------------------------------------------------
$ % $ % $ % $ %
Crude oil & NGL
Light crude oil &
NGL 7.72/bbl 11 6.85/bbl 9 6.08/bbl 9 6.59/bbl 9
Medium crude oil 8.34/bbl 17 11.04/bbl 19 8.17/bbl 17 8.73/bbl 18
Heavy crude oil &
bitumen 5.00/bbl 13 6.39/bbl 13 4.86/bbl 13 4.71/bbl 13
Natural gas 1.17/mcf 17 0.92/mcf 15 1.21/mcf 17 1.29/mcf 18
Total 6.81/boe 13 6.62/boe 13 6.22/boe 12 6.55/boe 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Upstream Revenue Mix
Three months Six months
ended June 30 ended June 30
Percentage of upstream net
revenues 2007 2006 2007 2006
----------------------------------------------------------------------------
Crude oil & NGL
Light crude oil & NGL 53 41 52 42
Medium crude oil 6 8 6 8
Heavy crude oil & bitumen 20 28 20 23
----------------------------------------------------------------------------
79 77 78 73
Natural gas 21 23 22 27
----------------------------------------------------------------------------
100 100 100 100
----------------------------------------------------------------------------
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OIL AND GAS PRODUCTION

(Please visit www.huskyenergy.ca to view the Production of Crude Oil and
Natural Gas chart.)

The following table discloses our gross daily production rate by location
and product type for five sequential quarters.

----------------------------------------------------------------------------
Daily Gross Production Three months ended

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

2007 2007 2006 2006 2006
----------------------------------------------------------------------------
Crude oil and NGL (mbbls/day)
Western Canada
Light crude oil & NGL 25.3 30.1 30.4 30.2 29.8
Medium crude oil 26.8 27.5 28.0 28.1 28.5
Heavy crude oil & bitumen 105.4 108.0 109.5 107.9 105.6
----------------------------------------------------------------------------
157.5 165.6 167.9 166.2 163.9

East Coast Canada
White Rose - light crude oil 90.3 89.4 79.4 75.9 53.0
Terra Nova - light crude oil 15.5 14.7 6.7 - 2.8
China
Wenchang - light crude
oil & NGL 13.2 13.6 11.7 11.1 12.1
----------------------------------------------------------------------------
276.5 283.3 265.7 253.2 231.8
----------------------------------------------------------------------------
Natural gas (mmcf/day) 615.7 640.0 662.2 669.1 672.8
----------------------------------------------------------------------------
Total (mboe/day) 379.1 390.0 376.1 364.7 344.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
2007 Gross Production Guidance Full Year Six months Year ended
Forecast ended June 30 Dec. 31

2007 2007 2006
----------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Light crude oil & NGL 128 - 135 146 111
Medium crude oil 28 - 30 27 29
Heavy crude oil & bitumen 122 - 130 107 108
----------------------------------------------------------------------------
278 - 295 280 248
Natural gas (mmcf/day) 670 - 690 628 672
Total barrels of
oil equivalent (mboe/day) 390 - 410 385 360
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Our current forecast for crude oil production in 2007 remains within our guidance range. Our current forecast for natural gas production in 2007 will likely be less than 670 mmcf/day as a result of the redeployment of capital, delayed natural gas well tie-ins and capital project delays.

Crude Oil Production

In the second quarter of 2007, Western Canada crude oil and NGL production declined 5% compared with the second quarter of 2006. The decline in production was mainly due to an early spring break-up combined with capital project delays and the disposition of properties in April 2007. Plans are being implemented to increase field work now that spring break-up is over.

Light crude oil production from the White Rose and Terra Nova oil fields off the East Coast of Canada averaged 106 mbbls/day during the second quarter of 2007 compared with 56 mbbls/day during the second quarter of 2006, an increase of 89%. At White Rose, the productive capacity of the field increased to 125 mbbls/day with the completion of the sixth production well in November 2006. A seventh production well was recently completed and has increased the field capacity to 140 mbbls/day. Our interest in Terra Nova production averaged 15.5 mbbls/day in the second quarter of 2007 compared with 2.8 mbbls/day in the second quarter of 2006. Terra Nova production recovered from mechanical issues, which were resolved in late 2006. During June 2007, production at Terra Nova was reduced by a scheduled turnaround.

At Wenchang in the South China Sea, production was 9% higher in the second quarter of 2007 compared to the same period in 2006. New production wells and well workovers in the fourth quarter of 2006 boosted production levels. NGL production also augmented crude oil production with the installation of gas liquid extraction facilities, which became operational in October 2006.

Natural Gas Production

All of our natural gas is produced in Western Canada. In the second quarter of 2007, the foothills of Alberta and British Columbia, the deep basin of Alberta and the plains of northeast British Columbia and northwest Alberta were the sources of 57% of our natural gas production; the remainder was from east central and southern Alberta and southern Saskatchewan.

Production of natural gas was down approximately 8% in the second quarter of 2007 compared with the second quarter of 2006 primarily due to property divestitures, infrastructure maintenance, capital project delays as well as restrictions due to an early spring break-up.

OPERATING COSTS

(Please visit www.huskyenergy.ca to view the Netback Unit Operating Costs chart.)

Operating costs in Western Canada averaged $11.10/boe in the second quarter of 2007 compared with $9.17/boe in the corresponding period in 2006, an increase of 21%. Unit operating costs in Western Canada, excluding the heavy oil operations in the Lloydminster area, averaged $9.82/boe in the second quarter of 2007 compared with $8.70/boe in the corresponding period in 2006, an increase of 13%.

The trend of increasing operating costs in Western Canada is related to the nature of exploitation necessary to manage production from maturing fields and new but more extensive and less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, more extensive pipeline systems, crude and water trucking, more extensive natural gas compression systems and complex tertiary recovery schemes. Cyclic steam and SAGD heavy oil and bitumen recovery schemes involve steaming cycles where the formation is heated while production ceases. These processes require higher energy consumption, workovers and generally more material costs. During the phase of thermal operations immediately after reservoir warm up, the steam/oil ratio is high and production of heavy oil or bitumen is low, resulting in higher than usual unit operating costs. In addition, higher levels of industry activity increase competition for resources and inflate costs. In managing rising operating costs, we attempt to keep our infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure fully utilized and optimized.

Operating costs at the East Coast offshore operations averaged $4.00/bbl in the second quarter of 2007 compared with $4.97/bbl in the second quarter of 2006. Unit operating costs in the second quarter of 2007 benefited from higher production volume from both White Rose and Terra Nova.

Operating costs at the South China Sea offshore operations averaged $3.04/bbl in the second quarter of 2007 compared with $2.41/bbl in the same period in 2006. Increased unit operating costs resulted from the maturing of the reservoir and the addition of liquids extraction to the operation in the third quarter of 2006.

DEPLETION, DEPRECIATION AND AMORTIZATION

(Please visit www.huskyenergy.ca to view the Depletion, Depreciation and Amortization chart.)

Depletion, depreciation and amortization ("DD&A") under the full cost method of accounting for oil and gas activities is calculated on a country-by-country basis. The DD&A rate is calculated by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as an equivalent barrel. The resultant dollar per barrel of oil equivalent is assigned to each barrel of oil equivalent that is produced to determine the DD&A expense for the period.

The Canadian cost centre DD&A averaged $11.79/boe in the second quarter of 2007 compared with $11.29/boe in the second quarter of 2006, an increase of 4%. The increase in DD&A results primarily from higher capital costs. Increasing capital is due to increased drilling and associated infrastructure in Western Canada and large capital investment developing offshore reserves off the East Coast of Canada.

DD&A in China averaged $11.89/boe in the second quarter of 2007 compared with $11.37/boe in the second quarter of 2006. Increasing unit DD&A results from declining reserve volume due to reservoir depletion.

OTHER

During the second quarter we recorded a $49 million gain on an embedded derivative related to a contract requiring payment in U.S. currency. The payments are expected to occur over the three-year period from mid 2008. This amount will fluctuate with the U.S./Cdn forward exchange rate until the actual contract settlement.



----------------------------------------------------------------------------
Operating Netbacks

Western Canada East Coast International Total
Three months
ended June 30 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Light Crude Oil
(per boe)(1)
Sales price $59.41 $62.34 $73.79 $76.57 $75.14 $77.80 $71.53 $72.56
Royalties(2) 6.32 7.14 6.04 1.82 14.43 16.35 6.87 5.21
Operating costs 13.89 12.88 4.00 4.97 3.04 2.41 5.53 6.95
----------------------------------------------------------------------------
39.20 42.32 63.75 69.78 57.67 59.04 59.13 60.40
----------------------------------------------------------------------------
Medium Crude Oil
(per boe)(1)
Sales price 47.81 57.34 - - - - 47.81 57.34
Royalties 8.38 10.76 - - - - 8.38 10.76
Operating costs 12.48 11.52 - - - - 12.48 11.52
----------------------------------------------------------------------------
26.95 35.06 - - - - 26.95 35.06
----------------------------------------------------------------------------
Heavy Crude Oil &
Bitumen (per boe)(1)
Sales price 38.30 47.92 - - - - 38.30 47.92
Royalties 4.97 6.34 - - - - 4.97 6.34
Operating costs 12.96 10.28 - - - - 12.96 10.28
----------------------------------------------------------------------------
20.37 31.30 - - - - 20.37 31.30
----------------------------------------------------------------------------
Total Crude Oil
(per boe)(1)
Sales price 43.06 52.08 73.79 76.57 75.14 77.80 56.31 59.28
Royalties 5.77 7.28 6.04 1.82 14.43 16.35 6.28 6.44
Operating costs 13.01 10.95 4.00 4.97 3.04 2.41 9.10 9.07
----------------------------------------------------------------------------
24.28 33.85 63.75 69.78 57.67 59.04 40.93 43.77
----------------------------------------------------------------------------
Natural Gas
(per mcfge)(3)
Sales price 7.04 6.23 - - - - 7.04 6.23
Royalties 1.37 1.16 - - - - 1.37 1.16
Operating costs 1.35 1.09 - - - - 1.35 1.09
----------------------------------------------------------------------------
4.32 3.98 - - - - 4.32 3.98
----------------------------------------------------------------------------
Equivalent Unit
(per boe)(1)
Sales price 42.78 46.13 73.79 76.57 75.14 77.80 52.56 52.19
Royalties 6.74 7.15 6.04 1.82 14.43 16.35 6.81 6.61
Operating costs 11.10 9.17 4.00 4.97 3.04 2.41 8.84 8.24
----------------------------------------------------------------------------
$24.94 $29.81 $63.75 $69.78 $57.67 $59.04 $36.91 $37.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Western Canada East Coast International Total

Six months
ended June 30 2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Light Crude Oil
(per boe)(1)
Sales price $58.08 $61.50 $70.17 $73.14 $71.65 $75.58 $68.13 $70.06
Royalties(2) 6.26 6.27 4.10 2.75 12.36 10.83 5.26 4.85
Operating costs 12.82 12.32 3.52 6.15 3.98 3.11 5.24 7.55
----------------------------------------------------------------------------
39.00 42.91 62.55 64.24 55.31 61.64 57.63 57.66
----------------------------------------------------------------------------
Medium Crude Oil
(per boe)(1)
Sales price 46.99 47.83 - - - - 46.99 47.83
Royalties 8.17 8.51 - - - - 8.17 8.51
Operating costs 13.03 12.02 - - - - 13.03 12.02
----------------------------------------------------------------------------
25.79 27.30 - - - - 25.79 27.30
----------------------------------------------------------------------------
Heavy Crude Oil &
Bitumen (per boe)(1)
Sales price 37.98 37.34 - - - - 37.98 37.34
Royalties 4.84 4.71 - - - - 4.84 4.71
Operating costs 12.40 10.76 - - - - 12.40 10.76
----------------------------------------------------------------------------
20.74 21.87 - - - - 20.74 21.87
----------------------------------------------------------------------------
Total Crude Oil
(per boe)(1)
Sales price 42.75 43.32 70.17 73.14 71.65 75.58 54.37 52.12
Royalties 5.65 5.66 4.10 2.75 12.36 10.83 5.39 5.25
Operating costs 12.57 11.25 3.52 6.15 3.98 3.11 8.79 9.60
----------------------------------------------------------------------------
24.53 26.41 62.55 64.24 55.31 61.64 40.19 37.27
----------------------------------------------------------------------------
Natural Gas
(per mcfge)(3)
Sales price 7.03 7.15 - - - - 7.03 7.15
Royalties 1.41 1.54 - - - - 1.41 1.54
Operating costs 1.34 1.04 - - - - 1.34 1.04
----------------------------------------------------------------------------
4.28 4.57 - - - - 4.28 4.57
----------------------------------------------------------------------------
Equivalent Unit
(per boe)(1)
Sales price 42.54 43.14 70.17 73.14 71.65 75.58 51.10 49.14
Royalties 6.73 7.09 4.10 2.75 12.36 10.83 6.21 6.53
Operating costs 10.82 9.24 3.52 6.15 3.98 3.11 8.59 8.52
----------------------------------------------------------------------------
$24.99 $26.81 $62.55 $64.24 $55.31 $61.64 $36.30 $34.09
----------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) During the second quarter of 2007, White Rose royalties increased to 5%
because the project, off the East Coast, achieved simple payout.
(3) Includes associated co-products converted to mcfge.

 


UPSTREAM CAPITAL EXPENDITURES

Capital expenditures during the second quarter of 2007 were funded primarily with internally generated cash flow.

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



----------------------------------------------------------------------------
2007 Capital Expenditure Guidance

(millions of dollars)
----------------------------------------------------------------------------
Western Canada - oil & gas $ 1,840
- oil sands 330
East Coast Canada 290
International 160
----------------------------------------------------------------------------
$ 2,620
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes our capital expenditures for the periods
presented.

----------------------------------------------------------------------------
Capital Expenditures Summary(1) Three months Six months
ended June 30 ended June 30

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Exploration
Western Canada $ 66 $ 148 $ 228 $ 308
East Coast Canada and Frontier - 3 5 23
International 19 36 24 36
----------------------------------------------------------------------------
85 187 257 367
----------------------------------------------------------------------------
Development
Western Canada 353 236 736 727
East Coast Canada 60 111 114 163
International 5 6 5 9
----------------------------------------------------------------------------
418 353 855 899
----------------------------------------------------------------------------
$ 503 $ 540 $ 1,112 $ 1,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period, capitalized administrative costs and
capitalized interest.

 


During the first six months of 2007, upstream capital expenditures were $1,112 million, $964 million (87%) in Western Canada, $119 million (11%) off the East Coast of Canada and $29 million (2%) offshore China, Indonesia and other international areas.

Western Canada

During the first six months of 2007, we invested $82 million on exploration in the foothills, deep basin and northern plains. We drilled 11 net wells in these regions resulting in 11 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 $246 million, primarily for exploitation and optimization.

We invested $122 million in the oil sands areas during the first six months of 2007, $39 million at Tucker where production is ramping up and $39 million on the Sunrise project. Front-end engineering design of the Sunrise project is currently 67% complete. We invested $44 million at our other oil sands areas principally at Saleski where we acquired additional lands, began to acquire seismic data and drilled several evaluation wells. We also drilled several stratigraphic test wells, water source and disposal evaluation wells and acquired seismic data at Caribou.

The following table discloses the number of gross and net exploration and development wells we completed during the quarters and six months ended June 30, 2007 and 2006. The data indicates that during the second quarter of 2007, 94% of the net exploration wells and 97% of the net development wells we drilled resulted in wells capable of commercial production.



----------------------------------------------------------------------------
Western Canada Wells Drilled
Three months Six months
ended June 30 ended June 30

2007 2006 2007 2006

Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Exploration Oil 13 13 7 7 33 33 29 29
Gas 4 3 36 18 69 59 194 104
Dry 1 1 3 3 10 10 18 17
----------------------------------------------------------------------------
18 17 46 28 112 102 241 150
----------------------------------------------------------------------------
Development Oil 58 54 69 57 196 184 179 160
Gas 6 4 37 23 174 141 262 216
Dry 2 2 2 2 12 12 11 11
----------------------------------------------------------------------------
66 60 108 82 382 337 452 387
----------------------------------------------------------------------------
Total 84 77 154 110 494 439 693 537
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Off the East Coast of Canada

During the first six months of 2007, capital expenditures in the region off the East Coast of Canada totalled $119 million. During June 2007, the seventh production well at the White Rose oil field was completed. Exploration expenditures in the East Coast offshore areas were $5 million during the first half of 2007 as drilling locations were being evaluated.

International

During the first half of 2007, we invested $24 million on international exploration for drilling location evaluations for the South and East China Seas and on the East Bawean II exploration block in the Java Sea. Capital expenditures on development were $5 million in the first half of 2007 primarily to advance the Madura natural gas and liquids project in Indonesia.

4.2 MIDSTREAM



----------------------------------------------------------------------------
Upgrading Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars,
except where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin $ 89 $ 136 $ 227 $ 344
Operating costs 47 53 105 119
Other recoveries (1) (2) (2) (3)
Depreciation and amortization 4 6 10 12
Income taxes 10 - 34 44
----------------------------------------------------------------------------
Earnings $ 29 $ 79 $ 80 $ 172
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Upgrader
throughput (1) (mbbls/day) 36.1 68.8 52.5 70.1
Synthetic crude
oil sales (mbbls/day) 32.9 56.9 45.3 60.2
Upgrading
differential ($/bbl) $30.41 $22.73 $26.42 $28.73
Unit margin ($/bbl) $29.74 $26.35 $27.64 $31.61
Unit operating
cost (2) ($/bbl) $14.37 $ 8.39 $11.05 $ 9.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1)Throughput includes diluent returned to the field.
(2)Based on throughput.

 


Second Quarter

(Please visit www.huskyenergy.ca to view the Upgrading Earnings Variance Analysis chart.)

Upgrading earnings in the second quarter of 2007 were $29 million, a decrease of $50 million from the second quarter of 2006 due primarily to a scheduled turnaround to perform maintenance and inspection. The turnaround, which shut the plant down for 49 days from May 10 to June 28, resulted in lower throughput in the second quarter of 2007 compared with the same quarter in 2006. The turnaround time was extended from 40 days to install two new coke drums. Operating costs during the second quarter of 2007 were $14.37/bbl compared with $8.39/bbl in the same quarter in 2006. Higher unit operating costs resulted from lower throughput.

Six Months

(Please visit www.huskyenergy.ca to view the Upgrading Earnings Variance Analysis chart.)

Upgrading earnings were lower in the first six months of 2007 than the corresponding period in 2006 due to the 49 day turnaround and also a lower differential between heavy crude oil and synthetic crude oil. Operating costs during the first six months of 2007 were $11.05/bbl compared with $9.33/bbl in the same period in 2006.



----------------------------------------------------------------------------
Infrastructure and Marketing Three months Six months
Earnings Summary ended June 30 ended June 30
(millions of dollars, except
where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin - pipeline $ 28 $ 28 $ 54 $ 54
- other
infrastructure
and marketing 48 52 120 120
----------------------------------------------------------------------------
76 80 174 174
Other expenses - 3 4 5
Depreciation and amortization 7 5 14 11
Income taxes 21 11 48 40
----------------------------------------------------------------------------
Earnings $ 48 $ 61 $ 108 $ 118
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline
throughput (mbbls/day) 506 480 500 490
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 



Second Quarter

Infrastructure and marketing earnings in the second quarter of 2007 decreased by $13 million compared with the second quarter of 2006 primarily due to lower margins on Lloyd Blend marketing and higher income taxes.

Six Months

Infrastructure and marketing earnings in the first six months of 2007 were marginally lower compared with the same period in 2006. Higher earnings from cogeneration operations were offset by lower Lloyd Blend margins and higher income taxes.

MIDSTREAM CAPITAL EXPENDITURES

Midstream capital expenditures totalled $161 million in the first six months of 2007: $121 million at the Lloydminster Upgrader, primarily for front-end engineering design for a proposed expansion, a small debottleneck project and reliability projects. The remaining $40 million was primarily spent on a pipeline extension between Lloydminster and Hardisty, Alberta.

4.3 REFINED PRODUCTS



----------------------------------------------------------------------------
Refined Products Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars, except
where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin - fuel sales $ 63 $ 57 $ 105 $ 79
- ancillary sales 10 8 19 16
- asphalt sales 36 32 49 53
----------------------------------------------------------------------------
109 97 173 148
Operating and other expenses 20 19 38 35
Depreciation and amortization 15 13 31 23
Income taxes 21 13 31 22
----------------------------------------------------------------------------
Earnings $ 53 $ 52 $ 73 $ 68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Number of fuel outlets 504 506
Light oil (million
sales litres/day) 8.6 8.6 8.8 8.6
Light oil retail (thousand
sales per outlet litres/day) 13.3 12.2 12.8 12.5
Prince George
refinery
throughput (mbbls/day) 8.4 3.7 9.7 6.5
Asphalt sales (mbbls/day) 19.5 24.9 18.4 21.3
Lloydminster
refinery
throughput (mbbls/day) 18.5 25.4 21.6 26.2
Ethanol (thousand
production litres/day) 305.9 25.2 313.7 25.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Second Quarter

Refined Products earnings in the second quarter of 2007 were marginally higher compared with the second quarter of 2006 primarily due to the addition of ethanol sales from the new Lloydminster ethanol plant, higher restaurant and convenience store income and higher asphalt product margins partially offset by lower fuel margins and sales volume, lower asphalt sales volume and higher depreciation created by the startup of the Lloydminster ethanol plant.

Six Months

Refined Products earnings in the first six months of 2007 increased by $5 million compared with the corresponding period of 2006. Higher earnings resulted from the ethanol sales from the Lloydminster ethanol plant, higher fuel and asphalt product margins and higher restaurant and convenience store income partially offset by lower asphalt sales volume and higher depreciation created by the startup of the Lloydminster ethanol plant.

REFINED PRODUCTS CAPITAL EXPENDITURES

Refined Products capital expenditures totalled $79 million during the first six months of 2007. The Minnedosa ethanol plant currently under construction accounted for $38 million, $25 million for marketing location upgrades and construction and $16 million for debottleneck and upgrade projects at the Lloydminster asphalt refinery, Prince George refinery, Lloydminster ethanol plant and asphalt distribution facilities.

4.4 CORPORATE



----------------------------------------------------------------------------
Corporate Summary Three months Six months
ended June 30 ended June 30
(millions of dollars)
income (expense) 2007 2006 2007 2006
----------------------------------------------------------------------------
Intersegment
eliminations - net $ (33) $ (23) $ (58) $ (14)
Administration expenses (10) (8) (21) (12)
Stock-based compensation (43) (15) (64) (85)
Accretion (1) (1) (2) (1)
Other - net (1) (4) (6) (8)
Depreciation and
amortization (7) (5) (12) (11)
Interest on debt (27) (32) (51) (70)
Interest capitalized 5 10 8 21
Foreign exchange - realized (35) (8) (29) 19
Foreign exchange - unrealized 71 40 66 18
Income taxes 36 10 63 53
----------------------------------------------------------------------------
Earnings (loss) $ (45) $ (36) $ (106) $ (90)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
(Gain) loss on translation of
U.S. dollar denominated long-
term debt
Realized $ - $ 1 $ - $ (30)
Unrealized (101) (67) (115) (37)
----------------------------------------------------------------------------
(101) (66) (115) (67)
Cross currency swaps 32 27 36 26
Other losses 33 7 42 4
----------------------------------------------------------------------------
$ (36) $ (32) $ (37) $ (37)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of period U.S. $0.867 U.S. $0.857 U.S. $0.858 U.S. $0.858
At end of period U.S. $0.940 U.S. $0.897 U.S. $0.940 U.S. $0.897
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


CORPORATE CAPITAL EXPENDITURES

During the first six months of 2007, corporate capital expenditures amounted to $12 million for various office space and facilities upgrades.

CONSOLIDATED INCOME TAXES

During the second quarter of 2007, consolidated income taxes consisted of $66 million of current taxes and $205 million of future taxes compared with current taxes of $210 million and future tax recovery of $229 million in the same period of 2006.

Lower current income taxes and higher future income taxes in the second quarter of 2007 were due to the deferral of White Rose income. Future income taxes in the second quarter of 2006 included a tax benefit of $328 million for changes in the tax rates of the governments of Canada, Alberta and Saskatchewan. Future income taxes in the second quarter of 2007 were reduced by a $30 million benefit in respect of a rate reduction by the Government of Canada.



----------------------------------------------------------------------------
Quarterly Financial Summary
Three months ended

(millions of dollars, June 30 March 31 Dec. 31 Sept. 30
except per share amounts and ratios) 2007 2007 2006 2006
----------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 3,163 $ 3,244 $ 3,084 $ 3,436
Segmented earnings
Upstream $ 636 $ 580 $ 453 $ 608
Midstream 77 111 105 87
Refined Products 53 20 10 28
Corporate and eliminations (45) (61) (26) (41)
----------------------------------------------------------------------------
Net earnings $ 721 $ 650 $ 542 $ 682
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per share - Basic and diluted (1) $ 0.85 $ 0.77 $ 0.64 $ 0.80
Cash flow from operations 1,257 1,324 1,207 1,224
Per share - Basic and diluted (1) 1.48 1.56 1.42 1.44
Ordinary quarterly dividend
per common share (1) 0.25 0.25 0.25 0.25
Special dividend per common share (1) - 0.25 - -
Total assets 17,969 17,781 17,933 17,324
Total long-term debt including
current portion 1,423 1,527 1,611 1,722
Return on equity (2) (percent) 27.1 32.1 31.8 34.2
Return on average capital
employed (2) (percent) 23.8 27.3 27.0 28.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Three months ended

(millions of dollars, June 30 March 31 Dec. 31 Sept. 30
except per share amounts and ratios) 2006 2006 2005 2005
----------------------------------------------------------------------------
Sales and operating revenues,
net of royalties $ 3,040 $ 3,104 $ 3,207 $ 2,594
Segmented earnings
Upstream $ 822 $ 412 $ 533 $ 445
Midstream 140 150 135 61
Refined Products 52 16 17 27
Corporate and eliminations (36) (54) (16) 23
----------------------------------------------------------------------------
Net earnings $ 978 $ 524 $ 669 $ 556
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per share - Basic and diluted (1) $ 1.15 $ 0.62 $ 0.79 $ 0.66
Cash flow from operations 1,103 967 1,197 944
Per share - Basic and diluted (1) 1.30 1.14 1.41 1.11
Ordinary quarterly dividend
per common share (1) 0.125 0.125 0.125 0.07
Special dividend per common share (1) - - 0.50 -
Total assets 16,328 15,855 15,716 14,670
Total long-term debt including
current portion 1,722 1,838 1,886 1,896
Return on equity (2) (percent) 34.8 29.6 29.2 22.9
Return on average capital
employed (2) (percent) 28.2 23.2 22.8 17.9
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts prior to June 30, 2007 as restated. Refer to Note 9 to the
Consolidated Financial Statements.
(2) Calculated for the 12 months ended for the dates shown.

 


4.5 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 2007. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.



----------------------------------------------------------------------------
Sensitivity Analysis

2007
Second
Quarter Effect on Pre-tax Effect on
Average Increase Cash Flow Net Earnings
----------------------------------------------------------------------------
($ millions)($/share)($ millions)($/share)
(5) (5)
Upstream and
Midstream
WTI benchmark
crude oil
price $ 65.03 U.S. $1.00/bbl 96 0.11 66 0.08
NYMEX
benchmark
natural gas
price(1) $ 7.55 U.S. $0.20/mmbtu 30 0.04 21 0.02
WTI/Lloyd
crude blend
differential
(2) $ 20.36 U.S. $1.00/bbl (40) (0.05) (28) (0.03)
Exchange rate
(U.S. $ per
Cdn $)(3) $ 0.911 U.S. $0.01 (71) (0.08) (50) (0.06)
Refined
Products
Light oil
margins $ 0.07 Cdn $0.005/litre 16 0.02 10 0.01
Asphalt
margins $ 18.49 Cdn $1.00/bbl 7 0.01 5 0.01
Consolidated
Period end
translation
of U.S. $ debt
(U.S. $ per
Cdn $) $0.940(4) U.S. $0.01 7 0.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes decrease in earnings related to natural gas consumption.
(2) Includes impact of upstream and upgrading operations only.
(3) Assumes no foreign exchange gains or losses on U.S. dollar denominated
long-term debt and other monetary items.
(4) U.S./Canadian dollar exchange rate at June 30, 2007.
(5) Based on 848.8 million common shares outstanding as of June 30, 2007.

 


5.0 LIQUIDITY AND CAPITAL RESOURCES

During the second quarter of 2007, cash flow from operating activities financed all of our capital requirements and dividend payment. At June 30, 2007, 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) 2007 2006 2007 2006
----------------------------------------------------------------------------
Cash flow - operating activities $ 1,136 $ 1,299 $ 1,808 $ 2,430
- financing activities $ (454) $ (409) $ (676) $ (848)
- investing activities $ (549) $ (773) $ (1,441) $(1,633)
Financial Ratios
Debt to capital employed (percent) 12.1 16.3
Corporate reinvestment ratio
(percent)(1)(2) 54 78
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated for the 12 months ended for the dates shown.
(2) Reinvestment ratio is based on net capital expenditures including
corporate acquisitions.

 


5.1 OPERATING ACTIVITIES

In the second quarter of 2007, cash generated from operating activities amounted to $1.1 billion compared with $1.3 billion in the second quarter of 2006. Lower cash flow from operating activities was primarily due to a decrease in non-cash working capital resulting primarily from an increase in prepaid expenditures.

5.2 FINANCING ACTIVITIES

In the second quarter of 2007, cash used in financing activities amounted to $454 million compared with $409 million in the second quarter of 2006. During the second quarter of 2007, cash was used for dividends and change in non-cash working capital primarily related to the sale of receivables. The debt issuances and repayments presented in the Consolidated Statements of Cash Flows include multiple drawings and repayments under revolving debt facilities.

5.3 INVESTING ACTIVITIES

In the second quarter of 2007, cash used in investing activities amounted to $549 million compared with $773 million in the second quarter of 2006. Cash invested in both periods was used primarily for capital expenditures, partially offset by asset sales.

5.4 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 capital 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. In addition, from time to time we engage in hedging a portion of our revenue to protect cash flow.

Working capital is the amount by which current assets exceed current liabilities. At June 30, 2007, our working capital was $372 million compared with a deficiency of $495 million at December 31, 2006. Working capital deficits are primarily the result of accounts payable related to capital expenditures for exploration and development. Settlement of these current liabilities is funded by cash provided by operating activities and, to the extent necessary, by bank borrowings. This position is a common characteristic of the oil and gas industry which, by the nature of its business, spends large amounts of capital.



----------------------------------------------------------------------------
June 30 Dec. 31
(millions of dollars) 2007 2006 Change
----------------------------------------------------------------------------
Current assets
Cash and cash
equivalents $ 133 $ 442 $ (309) Tax payment
Accounts receivable 1,138 1,284 (146) Lower gas volumes/prices
and sale of accounts
receivable

Inventories 519 428 91 Higher gas storage and
Terra Nova crude volumes
Prepaid expenses 182 25 157 Deposit for acquisition of
Lima refinery
-----------------------------------------------
1,972 2,179 (207)

Current liabilities
Accounts payable 915 1,268 353 Lower capital and operating
cost accruals
Accrued interest
payable 19 27 8
Income taxes payable - 615 615 Tax payment made
Other accrued
liabilities 666 664 (2)
Long-term debt due
within one year - 100 100 Payment of medium-term
notes
-----------------------------------------------
1,600 2,674 1,074
-----------------------------------------------
Working capital $ 372 $ (495) $ 867
-----------------------------------------------
-----------------------------------------------


----------------------------------------------------------------------------
Sources and Uses of Cash Six months Year ended
ended June 30 December 31
(millions of dollars) 2007 2006
----------------------------------------------------------------------------
Cash sourced
Cash flow from operations (1) $ 2,581 $ 4,501
Debt issue 1,867 1,226
Asset sales 327 34
Proceeds from exercise of stock options 4 3
----------------------------------------------------------------------------
4,779 5,764
----------------------------------------------------------------------------
Cash used
Capital expenditures 1,381 3,171
Debt repayment 1,967 1,493
Special dividend on common shares 212 -
Ordinary dividends on common shares 424 636
Settlement of asset retirement obligations 21 36
Settlement of cross currency swap - 47
Other 38 13
----------------------------------------------------------------------------
4,043 5,396
----------------------------------------------------------------------------
Net cash 736 368
Decrease in non-cash working capital (1,045) (94)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents (309) 274
Cash and cash equivalents - beginning of period 442 168
----------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 133 $ 442
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Cash flow from operations represents net earnings plus items not
affecting cash, which include accretion, depletion, depreciation and
amortization, future income taxes and foreign exchange.

----------------------------------------------------------------------------
Capital Structure (1)
June 30, 2007
Outstanding Available
(millions of dollars) (U.S. $) (Cdn $) (Cdn $)
----------------------------------------------------------------------------
Short-term bank debt $ - $ - $ 199
Long-term bank debt
Syndicated credit facility - - 1,250
Bilateral credit facilities - - 150
Medium-term notes (2) - 200
Capital securities 225 239
U.S. public notes 900 957
----------------------------------------------------------------------------
1,125 1,396 1,599
Fair value adjustment (2) - 1
Debt issue costs (3) - (13)
Unwound interest rate swaps (4) - 39
----------------------------------------------------------------------------
Total short-term and long-term debt $ 1,125 $ 1,423 $ 1,599
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares, retained earnings and
accumulated other comprehensive income $ 10,359
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Does not include U.S. $1.5 billion bridge financing for the Lima
refinery acquisition.
(2) The carrying value of the medium-term notes has been adjusted to fair
value to meet the accounting requirements for a fair value hedge.
Refer to Notes 3 and 11 to the Consolidated Financial Statements.
(3) Debt issue costs have been reclassified to long-term debt with the
adoption of financial instruments. Previously these deferred costs
were included in other assets. Refer to Notes 3 and 6 to the
Consolidated Financial Statements.
(4) The unamortized portion of the gain on previously unwound interest rate
swaps that would be designated as fair value hedges is required to be
included in the carrying value of long-term debt with the adoption of
financial instruments. Refer to Notes 3 and 6 to the Consolidated
Financial Statements.

 


At June 30, 2007, we had unused committed long and short-term borrowing credit facilities totalling $1.5 billion. A total of $71 million of our borrowing credit facilities were used in support of outstanding letters of credit and an additional $34 million of letters of credit were outstanding at June 30, 2007 and supported by dedicated letters of credit lines.

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 25 months 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 Management's Discussion and Analysis, no debt securities had been issued under this shelf prospectus.

At a special meeting of the shareholders on June 27, 2007, the shareholders approved a two-for-one share split of our issued and outstanding common shares. On June 27, 2007, the Company filed Articles of Amendment to effect the share split. All references to common share amounts, including common shares issued and outstanding, basic and diluted earnings per share, dividend per share, weighted average number of common shares outstanding and stock options granted, exercised, surrendered and forfeited have been retroactively restated to reflect the impact of the two-for-one share split. The common shares commenced trading on the Toronto Stock Exchange reflecting this split on July 9, 2007.

During the second quarter of 2007, we arranged short-term bridge financing from several banks to facilitate closing the acquisition of the Lima refinery on July 3, 2007. The bridge financing provided U.S. $1.5 billion while the remaining funds required were drawn under existing credit facilities. We plan to refinance the bridge financing by issuing securities in the long-term debt markets.

5.5 CREDIT RATINGS

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

5.6 CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Refer to Husky's 2006 annual Management's Discussion and Analysis under the caption "Cash Requirements," which summarizes contractual obligations and commercial commitments. There has been no material change in these amounts as at June 30, 2007.

5.7 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, 2007, $60 million of accounts receivable have been sold under the securitization program. The securitization program permits the sale of a maximum $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.

5.8 TRANSACTIONS WITH RELATED PARTIES

We did not have any significant transactions with related parties during the first six months of 2007 or during the year ended December 31, 2006.

5.9 SIGNIFICANT CUSTOMERS

We did not have any customers that constituted more than 10% of total sales and operating revenues during the first six months of 2007.

6.0 RISKS AND RISK MANAGEMENT

Husky is exposed to market risks and various operational risks. For a detailed discussion of these risks see our Annual Information Form filed on the Canadian Securities Administrators' web site, www.sedar.com, the U.S. Securities and Exchange Commission's web site, www.sec.gov or our web site www.huskyenergy.ca.

6.1 FINANCIAL RISKS

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 2007, interest rate risk management activities resulted in a decrease to interest expense of $1 million.

Cross currency swaps resulted in an addition to interest expense of $2 million in the first six months of 2007.

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 2007, 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 $2 million offset to interest expense in the first six months of 2007.

FOREIGN CURRENCY RISK MANAGEMENT

At June 30, 2007, 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, 2007, the cost of a U.S. dollar in Canadian currency was $1.0634.
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, 2007, 86% or $1.2 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 59% when cross currency swaps are considered.

7.0 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, 2006 available at www.sedar.com.

8.0 CHANGES IN ACCOUNTING POLICIES

FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges," section 1530, "Comprehensive Income" and section 3861, "Financial Instruments - Disclosure and Presentation." These standards have been adopted prospectively. See Note 3a) to the Consolidated Financial Statements.

ACCOUNTING CHANGES

In July 2006, the AcSB issued a revised CICA section 1506, "Accounting Changes." These amendments were made to harmonize section 1506 with current International Financial Reporting Standards. The changes covered by this section include changes in accounting policy, changes in accounting estimates and correction of errors. Under CICA section 1506, voluntary changes in accounting policy are only permitted if they result in financial statements that provide more reliable and relevant information. When a change in accounting policy is made, this change is applied retrospectively unless impractical. Changes in accounting estimates are generally applied prospectively and material prior period errors are corrected retrospectively. This section also outlines additional disclosure requirements when accounting changes are applied including justification for voluntary changes, complete description of the policy, primary source of GAAP and detailed effect on financial statement line items. CICA section 1506 is effective for fiscal years beginning on or after January 1, 2007.



9.0 OUTSTANDING SHARE DATA (1)
----------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31
(in thousands, except per share amounts) 2007 2006
----------------------------------------------------------------------------
Share price (2) High $ 46.65 $ 41.50
Low $ 35.40 $ 29.00
Close at end of period $ 43.85 $ 39.02
Average daily trading volume 1,061 1,210
Weighted average number of common shares
outstanding
Basic and diluted 848,637 848,412
Issued and outstanding at end of period (3)
Number of common shares 848,849 848,538
Number of stock options 32,205 11,656
Number of stock options exercisable 5,435 4,464
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) 2006 amounts as restated. Refer to Note 9 to the Consolidated Financial
Statements.
(2) Trading in the common shares of Husky Energy Inc. ("HSE") commenced on
the Toronto Stock Exchange on August 28, 2000. The Company is
represented in the S&P/TSX Composite, S&P/TSX Canadian Energy Sector
and in the S&P/TSX 60 indices.
(3) There were no significant issuances of common shares, stock options or
any other securities convertible into, or exercisable or exchangeable
for common shares during the period from June 30, 2007 to July 11, 2007.
During this period, 18 thousand stock options were surrendered for cash
and 279 thousand options were forfeited. At July 11, 2007, the Company
had 848,849 thousand common shares outstanding and there were 31,908
thousand stock options outstanding, of which 5,417 thousand were
exercisable.

 


10.0 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. 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:

----------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31
(millions of dollars) 2007 2006
----------------------------------------------------------------------------
Non-GAAP Cash flow from operations $ 2,581 $ 4,501
Settlement of asset retirement
obligations (21) (36)
Change in non-cash working capital (752) 544
----------------------------------------------------------------------------
GAAP Cash flow - operating activities $ 1,808 $ 5,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


11.0 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 2006 Annual Information Form filed in 2007 with Canadian regulatory agencies and Form 40-F filed with the U.S. 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.ca.

Use of Pronouns and Other Terms Denoting Husky

In this MD&A, unless the context indicates otherwise, 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, 2007 are compared with results for the three months ended June 30, 2006 and results for the six months ended June 30, 2007 are compared with results for the six months ended June 30, 2006. Discussions with respect to Husky's financial position as at June 30, 2007 are compared with its financial position at December 31, 2006.

Additional Reader Guidance

- The Consolidated Financial Statements and comparative financial information included in this Interim Report have been prepared in accordance with Canadian generally accepted accounting principles ("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.

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 well head.

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 those 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, 2006 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
MW megawatt
MWh megawatt-hour
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
OPEC Organization of Petroleum Exporting Countries
WCSB Western Canada Sedimentary Basin
SAGD Steam-assisted gravity drainage

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 Excludes capitalized administrative expenses,
capitalized interest, proceeds and other assets
Capital Program Capital expenditures not including capitalized
administrative expenses or capitalized interest
Carbonate Sedimentary rock primarily composed of calcium
carbonate (limestone) or calcium magnesium carbonate
(dolomite) which forms many petroleum reservoirs
Cash Flow from
Operations Earnings from operations plus non-cash charges before
settlement of asset retirement obligations and change
in non- cash working capital
Coalbed Methane Methane (CH4), the principal component of natural
gas, is adsorbed in the pores of coal seams
Contingent Resource Are those quantities of oil and gas estimated on a
given date to be potentially recoverable from known
accumulations but not currently economic
Dated Brent Prices which are dated less than 15 days prior to
loading for delivery
Design Rate Capacity Maximum continuous rated output of a plant based on
its design
Discovered Resource Are those quantities of oil and gas estimated on a
given date to be remaining in, plus those quantities
already produced from, known accumulations.
Discovered resources are divided into economic and
uneconomic categories, with the estimated future
recoverable portion classified as reserves and
contingent resources, respectively
Equity Shares and retained earnings
Feedstock Raw materials which are processed into petroleum
products
Front-end Engineering
Design Preliminary engineering and design planning, which
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/
Production A company's working interest share of reserves/
production before deduction of royalties
Hectare One hectare is equal to 2.47 acres
Nameplate Capacity The maximum rated output at which a plant or other
equipment was designed and constructed to safely and
efficiently operate under specified conditions
Near-month Prices Prices quoted for contracts for settlement during the
next month
NOVA Inventory
Transfer Exchange or transfer of title of gas that has been
received into the NOVA pipeline system but not yet
delivered to a connecting pipeline
Polymer A substance which has a molecular structure built up
mainly or entirely of many similar units bonded
together
Possible Reserves Are those additional reserves that are less certain
to be recovered than probable reserves. It is
unlikely that the actual remaining quantities
recovered will exceed the sum of the estimated
proved + probable + possible reserves
Surfactant A substance that tends to reduce the surface tension
of a liquid in which it is dissolved
Total Debt Long-term debt including current portion and bank
operating loans

 


12.0 FORWARD-LOOKING STATEMENTS

Certain statements in this release and Interim Report are forward-looking statements or 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. The Company is hereby providing cautionary statements identifying important factors that could cause the Company's 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" and "outlook") are not historical facts and are forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include: our general strategic plans, our production guidance, our White Rose and East Coast drilling, development and production plans, our production plans for the Tucker in-situ oil sands project, our Sunrise oil sands project design schedule and site preparation schedule, our Northwest Territories drilling program, the schedule of our offshore China geophysical and drilling programs, our Minnedosa plant commissioning schedule, the schedule and our plans for expanding our heavy crude oil mainline, schedule of our Lloydminster Upgrader expansion design plans and our plans to review options in respect of reconfiguring and expanding the Lima refinery. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this release and Interim Report. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.

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;

- 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;

- foreign exchange risk;

- 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 accuracy of our reserve estimates and estimated production levels.

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, the Company undertakes 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 the Company's 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) 2007 2006
----------------------------------------------------------------------------
(unaudited)

Assets
Current assets
Cash and cash equivalents $ 133 $ 442
Accounts receivable 1,138 1,284
Inventories 519 428
Prepaid expenses 182 25
----------------------------------------------------------------------------
1,972 2,179

Property, plant and equipment - (full
cost accounting) 26,439 25,552
Less accumulated depletion, depreciation
and amortization 10,708 10,002
----------------------------------------------------------------------------
15,731 15,550
Goodwill 160 160
Other assets 106 44
----------------------------------------------------------------------------
$ 17,969 $ 17,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 1,600 $ 2,574
Long-term debt due within one year (note 6) - 100
----------------------------------------------------------------------------
1,600 2,674
Long-term debt (note 6) 1,423 1,511
Other long-term liabilities (note 7) 789 756
Future income taxes 3,798 3,372
Commitments and contingencies (note 8)
Shareholders' equity
Common shares (note 9) 3,547 3,533
Retained earnings 6,826 6,087
Accumulated other comprehensive income (14) -
----------------------------------------------------------------------------
10,359 9,620
----------------------------------------------------------------------------
$ 17,969 $ 17,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares outstanding (millions) (note 9) 848.8 848.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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) 2007 2006 2007 2006
----------------------------------------------------------------------------
Sales and operating revenues, net of
royalties $ 3,163 $ 3,040 $ 6,407 $ 6,144
Costs and expenses
Cost of sales and operating expenses 1,701 1,638 3,480 3,465
Selling and administration expenses 52 50 90 77
Stock-based compensation 43 15 64 85
Depletion, depreciation and amortization 440 383 873 762
Interest - net (note 6) 22 22 43 49
Foreign exchange (note 6) (36) (32) (37) (37)
Other - net (51) 5 (45) 8
----------------------------------------------------------------------------
2,171 2,081 4,468 4,409
----------------------------------------------------------------------------
Earnings before income taxes 992 959 1,939 1,735
----------------------------------------------------------------------------
Income taxes
Current 66 210 138 414
Future 205 (229) 430 (181)
----------------------------------------------------------------------------
271 (19) 568 233
----------------------------------------------------------------------------
Net earnings 721 978 1,371 1,502
Other comprehensive income, net of
tax (note 3) 2 - 4 -
----------------------------------------------------------------------------
Comprehensive income (note 3) $ 723 $ 978 $ 1,375 $ 1,502
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share
Basic and diluted (note 9) $ 0.85 $ 1.15 $ 1.61 $ 1.77
Weighted average number of common shares
outstanding (millions)
Basic and diluted (note 9) 848.7 848.4 848.6 848.3
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

(millions of dollars) (unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Retained earnings, beginning of period $ 6,317 $ 4,415 $ 6,087 $ 3,997
Net earnings 721 978 1,371 1,502
Dividends on common shares - ordinary (212) (106) (424) (212)
- special - - (212) -
Adoption of financial instruments
(notes 3, 11) - - 4 -
----------------------------------------------------------------------------
Retained earnings, end of period $ 6,826 $ 5,287 $ 6,826 $ 5,287
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated other comprehensive income,
beginning of period $ (16) $ - $ - $ -
Adoption of financial instruments
(notes 3, 11) - - (18) -
Other comprehensive income, net
of tax (note 3) 2 - 4 -
----------------------------------------------------------------------------
Accumulated other comprehensive income,
end of period $ (14) $ - $ (14) $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating activities
Net earnings $ 721 $ 978 $ 1,371 $ 1,502
Items not affecting cash
Accretion (note 7) 10 9 22 18
Depletion, depreciation
and amortization 440 383 873 762
Future income taxes 205 (229) 430 (181)
Foreign exchange (69) (41) (79) (42)
Other (50) 3 (36) 11
Settlement of asset retirement
obligations (7) (6) (21) (14)
Change in non-cash working
capital (note 4) (114) 202 (752) 374
----------------------------------------------------------------------------
Cash flow - operating activities 1,136 1,299 1,808 2,430
----------------------------------------------------------------------------
Financing activities
Bank operating loans financing - net (83) (132) - -
Long-term debt issue 1,432 251 1,867 1,226
Long-term debt repayment (1,432) (300) (1,967) (1,322)
Proceeds from exercise of
stock options 3 - 4 1
Dividends on common shares (212) (106) (636) (212)
Change in non-cash working
capital (note 4) (162) (122) 56 (541)
----------------------------------------------------------------------------
Cash flow - financing activities (454) (409) (676) (848)
----------------------------------------------------------------------------
Available for investing 682 890 1,132 1,582
----------------------------------------------------------------------------
Investing activities
Capital expenditures (647) (683) (1,381) (1,543)
Asset sales 327 1 327 33
Other (36) (12) (38) (13)
Change in non-cash working
capital (note 4) (193) (79) (349) (110)
----------------------------------------------------------------------------
Cash flow - investing activities (549) (773) (1,441) (1,633)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 133 117 (309) (51)
Cash and cash equivalents, beginning
of period - - 442 168
----------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 133 $ 117 $ 133 $ 117
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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, 2007 (unaudited)
Except where indicated, all dollar amounts are in millions.


Note 1 Segmented Financial Information
----------------------------------------------------------------------------
Upstream Midstream
Infrastructure
and
Upgrading Marketing
2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended June 30
Sales and operating
revenues, net of
royalties $ 1,593 $ 1,451 $ 229 $ 404 $ 2,521 $ 2,267
Costs and expenses
Operating, cost of sales,
selling, general and other 295 308 186 319 2,445 2,190
Depletion,
depreciation and
amortization 407 354 4 6 7 5
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
702 662 190 325 2,452 2,195
----------------------------------------------------------------------------
Earnings (loss) before
income taxes 891 789 39 79 69 72
Current income taxes 3 156 - 29 29 20
Future income taxes 252 (189) 10 (29) (8) (9)
----------------------------------------------------------------------------
Net earnings (loss) $ 636 $ 822 $ 29 $ 79 $ 48 $ 61
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures -
Three months ended
June 30 (2) $ 503 $ 540 $ 74 $ 38 $ 3 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended June 30
Sales and operating
revenues, net of royalties $ 3,158 $ 2,738 $ 588 $ 809 $ 5,076 $ 4,731
Costs and expenses
Operating, cost of sales,
selling, general and other 618 619 464 581 4,906 4,562
Depletion, depreciation
and amortization 806 705 10 12 14 11
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
1,424 1,324 474 593 4,920 4,573
----------------------------------------------------------------------------
Earnings (loss) before
income taxes 1,734 1,414 114 216 156 158
Current income taxes 25 299 1 53 45 39
Future income taxes 493 (119) 33 (9) 3 1
----------------------------------------------------------------------------
Net earnings (loss) $ 1,216 $ 1,234 $ 80 $ 172 $ 108 $ 118
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital employed -
As at June 30 $ 9,786 $ 9,274 $ 816 $ 691 $ 852 $ 353
Capital expenditures -
Six months ended
June 30 (2) $ 1,112 $ 1,266 $ 121 $ 75 $ 40 $ 12
Total assets -
As at June 30 $13,974 $13,277 $ 1,193 $ 1,064 $ 1,147 $ 732
----------------------------------------------------------------------------
----------------------------------------------------------------------------


---------------------------------------------------------------------------
Corporate and
Refined Products Eliminations(1) Total

2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended June 30
Sales and operating
revenues, net of
royalties $ 709 $ 674 $(1,889)$(1,756)$ 3,163 $ 3,040
Costs and expenses
Operating, cost of sales,
selling, general and other 620 596 (1,801) (1,705) 1,745 1,708
Depletion, depreciation and
amortization 15 13 7 5 440 383
Interest - net - - 22 22 22 22
Foreign exchange - - (36) (32) (36) (32)
----------------------------------------------------------------------------
635 609 (1,808) (1,710) 2,171 2,081
----------------------------------------------------------------------------
Earnings (loss) before
income taxes 74 65 (81) (46) 992 959
Current income taxes 7 3 27 2 66 210
Future income taxes 14 10 (63) (12) 205 (229)
----------------------------------------------------------------------------
Net earnings (loss) $ 53 $ 52 $ (45)$ (36)$ 721 $ 978
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures -
Three months ended
June 30 (2) $ 41 $ 76 $ 8 $ (1)$ 629 $ 664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended June 30
Sales and operating
revenues, net of
royalties $ 1,327 $ 1,220 $(3,742)$(3,354)$ 6,407 $ 6,144
Costs and expenses
Operating, cost of sales,
selling, general and other 1,192 1,107 (3,591) (3,234) 3,589 3,635
Depletion, depreciation
and amortization 31 23 12 11 873 762
Interest - net - - 43 49 43 49
Foreign exchange - - (37) (37) (37) (37)
----------------------------------------------------------------------------
1,223 1,130 (3,573) (3,211) 4,468 4,409
----------------------------------------------------------------------------
Earnings (loss) before
income taxes 104 90 (169) (143) 1,939 1,735
Current income taxes 15 12 52 11 138 414
Future income taxes 16 10 (115) (64) 430 (181)
----------------------------------------------------------------------------
Net earnings (loss) $ 73 $ 68 $ (106)$ (90)$ 1,371 $ 1,502
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital employed -
As at June 30 $ 796 $ 585 $ (468)$ (367)$11,782 $10,536
Capital expenditures -
Six months ended
June 30 (2) $ 79 $ 138 $ 12 $ 8 $ 1,364 $ 1,499
Total assets -
As at June 30 $ 1,304 $ 998 $ 351 $ 257 $17,969 $16,328
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, capitalized administrative costs and
capitalized interest.

 


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, 2006, 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, 2006. Certain prior years' amounts have been reclassified to conform with current presentation.

Note 3 Changes in Accounting Policies

a) Financial Instruments and Hedging Activities

Effective January 1, 2007, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3855, "Financial Instruments - Recognition and Measurement," section 3865, "Hedges," section 1530, "Comprehensive Income" and section 3861, "Financial Instruments - Disclosure and Presentation." The Company has adopted these standards prospectively and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income.

i) Financial Instruments

All financial instruments must initially be recognized at fair value on the balance sheet. The Company has classified each financial instrument into the following categories: held for trading financial assets and financial liabilities, loans or receivables, held to maturity investments, available for sale financial assets, and other financial liabilities. Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income and are transferred to earnings when the asset is derecognized. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method.

Upon adoption and with any new financial instrument, an irrevocable election is available that allows entities to classify any financial asset or financial liability as held for trading, even if the financial instrument does not meet the criteria to designate it as held for trading. The Company has not elected to classify any financial assets or financial liabilities as held for trading unless they meet the held for trading criteria. A held for trading financial instrument is not a loan or receivable and includes one of the following criteria:

- is a derivative, except for those derivatives that have been designated as effective hedging instruments;

- has been acquired or incurred principally for the purpose of selling or repurchasing in the near future; or

- is part of a portfolio of financial instruments that are managed together and for which there is evidence of a recent actual pattern of short-term profit taking.

For financial assets and financial liabilities that are not classified as held for trading, the transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to the fair value initially recognized for that financial instrument. These costs are expensed to earnings using the effective interest rate method.

ii) Derivative Instruments and Hedging Activities

Derivative instruments are utilized by the Company to manage market risk against the volatility in commodity prices, foreign exchange rates and interest rate exposures. The Company's policy is not to utilize derivative instruments for speculative purposes. The Company may choose to designate derivative instruments as hedges. Hedge accounting continues to be optional.

At the inception of a hedge, the Company formally documents the designation of the hedge, the risk management objectives, the hedging relationships between the hedged items and hedging items and the method for testing the effectiveness of the hedge, which must be reasonably assured over the term of the hedge. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company formally assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.

All derivative instruments are recorded on the balance sheet at fair value in either accounts receivable, other assets, accounts payable and accrued liabilities, or other long-term liabilities. Freestanding derivative instruments are classified as held for trading financial instruments. Gains and losses on these instruments are recorded in other expenses in the consolidated statement of earnings in the period they occur. Derivative instruments that have been designated and qualify for hedge accounting have been classified as either fair value or cash flow hedges. For fair value hedges, the gains or losses arising from adjusting the derivative to its fair value are recognized immediately in earnings along with the gain or loss on the hedged item. For cash flow hedges, the effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the consolidated statement of earnings, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Any hedge ineffectiveness is immediately recognized in earnings. For any hedging relationship that has been determined to be ineffective, hedge accounting is discontinued on a prospective basis.

The Company may enter into commodity price contracts to hedge anticipated sales of crude oil and natural gas production to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream oil and gas revenues as the related sales occur.

The Company may enter into commodity price contracts to offset fixed price contracts entered into with customers and suppliers to retain market prices while meeting customer or supplier pricing requirements. Gains and losses from these contracts are recognized in midstream revenues or costs of sales.

The Company may enter into power price contracts to hedge anticipated purchases of electricity to manage its exposure to price fluctuations. Gains and losses from these contracts are recognized in upstream operating expenses as the related purchases occur.

The Company may enter into interest rate swap agreements to hedge its fixed and floating interest rate mix on long-term debt. Gains and losses from these contracts are recognized as an adjustment to the interest expense on the hedged debt instrument.

The Company may enter into foreign exchange contracts to hedge its foreign currency exposures on U.S. dollar denominated long-term debt. Gains and losses on these instruments related to foreign exchange are recorded in the foreign exchange expense in the period to which they relate, offsetting the respective foreign exchange gains and losses recognized on the underlying foreign currency long-term debt. The remaining portion of the gain or loss is recorded in accumulated other comprehensive income and is adjusted for changes in the fair value of the instrument over the life of the debt.

The Company may enter into foreign exchange forwards and foreign exchange collars to hedge anticipated U.S. dollar denominated crude oil and natural gas sales. Gains and losses on these instruments are recognized as an adjustment to upstream oil and gas revenues when the sale is recorded.

For cash flow hedges that have been terminated or cease to be effective, prospective gains or losses on the derivative are recognized in earnings. Any gain or loss that has been included in accumulated other comprehensive income at the time the hedge is discontinued continues to be deferred in accumulated other comprehensive income until the original hedged transaction is recognized in earnings. However, if the likelihood of the original hedged transaction occurring is no longer probable, the entire gain or loss in accumulated other comprehensive income related to this transaction is immediately reclassified to earnings.

Fair values of the derivatives are based on quoted market prices where available. The fair values of swaps and forwards are based on forward market prices. If a forward price is not available for a commodity based forward, a forward price is estimated using an existing forward price adjusted for quality or location.

iii) Embedded Derivatives

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not clearly and closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not classified as held for trading or designated at fair value. The Company has selected January 1, 2003 as its transition date for accounting for any potential embedded derivatives.

iv) Comprehensive Income

Comprehensive income consists of net earnings and other comprehensive income ("OCI"). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge and the change in fair value of any available for sale financial instruments. Amounts included in OCI are shown net of tax. Accumulated other comprehensive income is a new equity category comprised of the cumulative amounts of OCI.

b) Accounting Changes

Effective January 1, 2007, the Company adopted the revised recommendations of CICA section 1506, "Accounting Changes."

The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007.

c) Inventories

The Company has assessed CICA section 3031, "Inventories," which is effective January 1, 2008 and has determined that there will be no impact to the financial statements.



Note 4 Cash Flows - Change in Non-cash Working Capital
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2007 2006 2007 2006
----------------------------------------------------------------------------
a) Change in non-cash
working capital was as
follows:
Decrease (increase) in
non-cash working capital
Accounts receivable $ 147 $ 5 $ 149 $ 109
Inventories (99) (26) (91) 6
Prepaid expenses (143) (23) (144) (19)
Accounts payable and
accrued liabilities (374) 45 (959) (373)
----------------------------------------------------------------------------
Change in non-cash working
capital $ (469) $ 1 $(1,045) $ (277)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities $ (114) $ 202 $ (752) $ 374
Financing activities (162) (122) 56 (541)
Investing activities (193) (79) (349) (110)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Other cash flow
information:
Cash taxes paid $ 72 $ 44 $ 840 $ 173
Cash interest paid 39 47 62 79
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Note 5 Bank Operating Loans

At June 30, 2007, the Company had unsecured short-term borrowing lines of credit with banks totalling $270 million (December 31, 2006 - $220 million). As at June 30, 2007 and December 31, 2006, there were no bank operating loans outstanding. As at June 30, 2007, letters of credit under these lines of credit totalled $71 million (December 31, 2006 - $19 million).



Note 6 Long-term Debt
----------------------------------------------------------------------------
June 30 Dec. 31 June 30 Dec. 31

Maturity 2007 2006 2007 2006
----------------------------------------------------------------------------
Cdn $ Amount U.S. $ Denominated
Long-term debt
Medium-term
notes (1) 2009 $ 201 $ 300 $ - $ -
6.25% notes 2012 425 466 400 400
7.55% debentures 2016 213 233 200 200
6.15% notes 2019 319 350 300 300
8.90% capital
securities 2028 239 262 225 225
Debt issue
costs (2) (13) - - -
Unwound interest
rate swaps (3) 39 - - -
----------------------------------------------------------------------------
Total long-term
debt 1,423 1,611 $ 1,125 $ 1,125
----------------------
----------------------
Amount due within
one year - (100)
--------------------------------------------------
$ 1,423 $ 1,511
--------------------------------------------------
--------------------------------------------------
(1) The carrying value of the medium-term notes has been adjusted to fair
value to meet the accounting requirements for a fair value hedge. Refer
to note 11, Financial Instruments and Risk Management.
(2) Debt issue costs have been reclassified to long-term debt with the
adoption of financial instruments. Previously, these deferred costs were
included in other assets.
(3) The unamortized portion of the gain on previously unwound interest rate
swaps that would be designated as fair value hedges is required to be
included in the carrying value of long-term debt with the adoption of
financial instruments.

 


During the second quarter of 2007, the Company arranged short-term bridge financing from several banks to facilitate closing the acquisition of the Lima refinery on July 3, 2007. The bridge financing provided U.S. $1.5 billion while the remaining funds required were drawn under existing credit facilities. The Company plans to refinance the bridge financing by issuing securities in the long-term debt markets.



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

2007 2006 2007 2006
----------------------------------------------------------------------------
Long-term debt $ 26 $ 31 $ 54 $ 68
Short-term debt 2 2 3 3
----------------------------------------------------------------------------
28 33 57 71
Amount capitalized (5) (10) (8) (21)
----------------------------------------------------------------------------
23 23 49 50
Interest income (1) (1) (6) (1)
----------------------------------------------------------------------------
$ 22 $ 22 $ 43 $ 49
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

2007 2006 2007 2006
----------------------------------------------------------------------------
Gain on translation of U.S.
dollar denominated
long-term debt $ (101) $ (66) $ (115) $ (67)
Cross currency swaps 32 27 36 26
Other losses 33 7 42 4
----------------------------------------------------------------------------
$ (36) $ (32) $ (37) $ (37)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Note 7 Other Long-term Liabilities

Asset Retirement Obligations

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

2007 2006
----------------------------------------------------------------------------
Asset retirement obligations at beginning of period $ 622 $ 557
Liabilities incurred 16 10
Liabilities disposed (14) -
Liabilities settled (21) (14)
Accretion 22 18
----------------------------------------------------------------------------
Asset retirement obligations at end of period $ 625 $ 571
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


At June 30, 2007, the estimated total undiscounted inflation adjusted amount required to settle outstanding asset retirement obligations was $3.8 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 6.5%.

Note 8 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 9 Share Capital

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

On June 27, 2007, the Company filed Articles of Amendment to implement a two-for-one share split of its issued and outstanding common shares. The share split was approved at a special meeting of the shareholders on June 27, 2007. All references to common share amounts, including common shares issued and outstanding, basic and diluted earnings per share, dividend per share, weighted average number of common shares outstanding and stock options granted, exercised, surrendered and forfeited have been retroactively restated to reflect the impact of the two-for-one share split.



Common Shares

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

Six months ended June 30

2007 2006
----------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
----------------------------------------------------------------------------
Balance at beginning
of period 848,537,018 $ 3,533 848,250,156 $ 3,523
Options exercised 311,592 14 124,530 4
----------------------------------------------------------------------------
Balance at June 30 848,848,610 $ 3,547 848,374,686 $ 3,527
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Stock Options

In accordance with the Company's stock option plan, common share options may be granted to directors, 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 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.

Effective February 26, 2007, the Board of Directors approved amendments to the Company's stock option plan to also provide for performance vesting of stock options. Shareholder ratification was obtained at the Annual and Special Meeting of Shareholders on April 19, 2007. Performance options granted may vest in 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 exercisable will depend upon the Company's performance measured over three calendar years. If the Company's performance is below the specified level compared to its industry peer group, the performance options awarded will be forfeited. If the Company's performance is at or above the specified level compared to its industry peer group, the number of performance options exercisable shall be determined by the Company's relative ranking.

On April 19, 2007, the Company granted 25,211,082 options at a price of $41.66, including 15,126,650 performance options.



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

Six months ended June 30

2007 2006
----------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
----------------------------------------------------------------------------
Outstanding, beginning
of period 11,656 $ 16.40 14,570 $ 12.91
Granted 25,211 $ 41.66 1,134 $ 34.66
Exercised for common
shares (311) $ 11.93 (124) $ 10.49
Surrendered for cash (3,712) $ 13.32 (1,668) $ 11.42
Forfeited (639) $ 38.79 (346) $ 20.09
----------------------------------------------------------------------------
Outstanding at June 30 32,205 $ 36.07 13,566 $ 14.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable at
June 30 5,435 $ 12.43 6,291 $ 11.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

June 30, 2007

Outstanding Options Options Exercisable
----------------------------------------------------------------------------
Weighted
Weighted Average Weighted
Number of Average Contractual Number of Average
Range of Options Exercise Life Options Exercise
Exercise Price (thousands) Prices (years) (thousands) Prices
----------------------------------------------------------------------------
$ 6.81 - $9.99 61 $ 7.21 1 61 $ 7.21
$ 10.00 - $10.99 62 $ 10.32 1 62 $ 10.32
$ 11.00 - $12.99 5,048 $ 11.74 2 5,048 $ 11.74
$ 13.00 - $19.99 312 $ 15.95 2 81 $ 14.87
$ 20.00 - $29.99 596 $ 25.87 3 49 $ 26.07
$ 30.00 - $39.99 1,307 $ 35.90 4 134 $ 35.13
$ 40.00 - $41.66 24,819 $ 41.66 5 - $ -
----------------------------------------------------------------------------
32,205 $ 36.07 4 5,435 $ 12.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


A downward adjustment of $0.175 was made to the exercise price of all outstanding stock options effective February 28, 2007, pursuant to the terms of the stock option plan under which the options were issued as a result of the special $0.25 per share dividend that was declared in February 2007.



Note 10 Employee Future Benefits

Total benefit costs recognized were as follows:
----------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30

2007 2006 2007 2006
----------------------------------------------------------------------------
Employer current service
cost $ 6 $ 5 $ 12 $ 9
Interest cost 3 3 5 5
Expected return on plan
assets (3) (2) (5) (3)
Amortization of net
actuarial losses 1 - 2 -
----------------------------------------------------------------------------
$ 7 $ 6 $ 14 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Note 11 Financial Instruments and Risk Management

As described in note 3a), on January 1, 2007, the Company adopted the new CICA requirements relating to financial instruments. The following table summarizes the prospective adoption adjustments that were required as at January 1, 2007.



----------------------------------------------------------------------------
December 31, January 1,
2006 Adoption 2007
(As Reported) Adjustment (As Restated)
----------------------------------------------------------------------------
Consolidated Balance Sheets
Assets
Accounts receivable $ 1,284 $ 6 $ 1,290
Prepaid expenses 25 (2) 23
Other assets 44 (7) 37
Liabilities and Shareholders'
Equity
Accounts payable and accrued
liabilities 2,574 (5) 2,569
Long-term debt due within one
year 100 (2) 98
Long-term debt 1,511 34 1,545
Other long-term liabilities 756 (10) 746
Future income taxes 3,372 (6) 3,366
Retained earnings 6,087 4 6,091
Accumulated other
comprehensive income - (18) (18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Commodity Price Risk Management

Natural Gas Contracts

At June 30, 2007, the Company had the following external offsetting
physical purchase and sale natural gas contracts, which met the definition
of a derivative instrument:

----------------------------------------------------------------------------
Volumes
(mmcf) Fair Value
----------------------------------------------------------------------------
Physical purchase contracts 39,903 $ 2
Physical sale contracts (39,903) $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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

Interest Rate Risk Management

At June 30, 2007, 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 $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


This contract has been recorded at fair value in other assets. During the first six months of 2007, the Company realized a gain of $1 million (2006 - gain of $1 million) from interest rate risk management activities.



Foreign Currency Risk Management

At June 30, 2007, the Company had a cash flow hedge using the following
cross currency debt swaps:

----------------------------------------------------------------------------
Canadian Interest Rate Fair
Debt Swap Amount Equivalent Swap Maturity (percent) Value
----------------------------------------------------------------------------
6.25% notes U.S. $ 150 $ 212 June 15, 2012 7.41 $ (70)
6.25% notes U.S. $ 75 $ 90 June 15, 2012 5.65 $ (10)
6.25% notes U.S. $ 50 $ 59 June 15, 2012 5.67 $ (6)
6.25% notes U.S. $ 75 $ 88 June 15, 2012 5.61 $ (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 remainder of the loss has been included in other comprehensive income.

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 2007, the impact of these contracts was a gain of $2 million (2006 - gain of $6 million).

Embedded Derivatives

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 other assets and the resulting unrealized gain has been recorded in other expenses in the consolidated statement of earnings for the period. In the first six months of 2007, the impact was an unrealized gain on embedded derivatives of $48.7 million.

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, 2007, $60 million of accounts receivable had been sold under the program (December 31, 2006 - nil). In July 2007, a further $290 million of accounts receivable was sold.

Note 12 Subsequent Event

On May 2, 2007, the Company entered into an agreement, which subsequently closed on July 3, 2007, to acquire a refinery in Lima, Ohio from Valero Energy Corporation through the purchase of all of the issued and outstanding shares of Lima Refining Company effective July 1, 2007. The purchase price was U.S. $1.9 billion plus net working capital. An additional U.S. $540 million was paid for feedstock and product inventory. The Company is currently working on the allocation of the purchase price.

Husky Energy Inc. will host a conference call for analysts and investors on Thursday, July 19, 2007 at 4:15 p.m. Eastern time to discuss Husky's second quarter results. To participate please dial 1-800-319-4610 beginning at 4:05 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.ca, under Investor Relations. The webcast will be archived for approximately 90 days.

Those unable to listen to the call live may listen to a recording by dialing 1-800-319-6413 one hour after the completion of the call, approximately 6:15 p.m. (EST), then dialing reservation number 5229. The Postview will be available until Sunday, August 19, 2007.

Media are invited to listen to the conference call by dialing 1-800-597-1419 beginning at 4:05 p.m. Eastern time.



FOR FURTHER INFORMATION PLEASE CONTACT:

Husky Energy Inc.
Tanis Thacker
Manager, Investor Relations
(403) 298-6747
(403) 298-6515 (FAX)
Email: Investor.Relations@huskyenergy.ca
Website: www.huskyenergy.ca