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FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy Reports 2007 Annual and Fourth Quarter Results

Feb 04, 2008 - 09:51 ET

CALGARY, ALBERTA--(Marketwire - Feb. 4, 2008) - Husky Energy Inc. is pleased to announce annual net earnings of $3.2 billion or $3.79 per share (diluted), up 18% over the year 2006 from $2.7 billion or $3.21 per share (diluted). Cash flow from operations improved by 21% to $5.4 billion or $6.39 per share (diluted), compared with $4.5 billion or $5.30 per share (diluted) in 2006. Sales and operating revenues, net of royalties, were $15.5 billion in 2007, an increase of 23% over the $12.7 billion in 2006.

"Husky Energy has successfully achieved record performance in all areas of operations: upstream, midstream and downstream," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "With cash flow in excess of $5.4 billion and proved and probable reserves over 3.2 billion barrels of oil equivalent, Husky is well positioned to capitalize on expansion opportunities."

During the year, Husky progressed a number of significant projects including:

- the purchase of the Lima refinery;

- the agreement with BP to create an integrated oil sands joint venture business;

- the expansion of the Lloydminster upgrader to 82,000 barrels per day;

- the conclusion of negotiations with the Government of Newfoundland and Labrador on fiscal terms for satellite developments at White Rose;

- the finalization of the Madura field gas sale and purchase agreements; and

- the completion of the ethanol plant in Minnedosa.

Husky's financial position remains strong. Including the acquisition of the Lima refinery, the Company's debt to capital employed was 19% at December 31, 2007 compared with 14% at December 31, 2006. Debt to cash flow from operations increased to 0.5 times at December 31, 2007 from 0.4 times at December 31, 2006.

Production in 2007 was 377,000 barrels of oil equivalent per day, compared with 360,000 barrels of oil equivalent per day in 2006, an increase of 5%. Crude oil and natural gas liquids production increased 10% to 273,000 barrels per day, compared with 248,000 barrels per day in 2006. Natural gas production was 623 million cubic feet per day, compared with 672 million cubic feet per day in 2006, reflecting Husky's decision to adjust its drilling program in Western Canada due to weakening gas market conditions and the higher cost environment.

Husky's 2007 fourth quarter net earnings were $1.1 billion or $1.26 per share (diluted) compared with $542 million or $0.64 per share (diluted) for the fourth quarter of 2006. Net earnings for the fourth quarter of 2007 included a tax benefit of $365 million due to federal tax rate reductions, while there were no similar rate reductions in the fourth quarter of 2006. 2007 fourth quarter cash flow from operations was $1.4 billion or $1.68 per share compared with $1.2 billion or $1.42 per share in the fourth quarter of 2006. Sales and operating revenues, net of royalties, were $4.8 billion in the fourth quarter of 2007, compared with $3.1 billion in the fourth quarter of 2006.

Production for the fourth quarter of 2007 was 367,500 barrels of oil equivalent per day, compared with 376,100 barrels of oil equivalent per day in 2006. Crude oil and natural gas liquids production for the quarter was 264,500 barrels per day, compared with 265,700 barrels per day in 2006. Natural gas production was 617.8 million cubic feet per day, compared with 662.2 million cubic feet per day in 2006 due to a weakening market price for natural gas.

During the quarter, Husky announced a joint venture agreement with BP to create an integrated oil sands joint venture business. Under the terms of the agreement, Husky will contribute its Sunrise assets located in the Athabasca oil sands in northeast Alberta, Canada and BP will contribute its Toledo refinery located in Ohio, USA. The transaction, which is subject to the execution of final agreements and regulatory approval, is expected to close in the first quarter of 2008 with an effective date of January 1, 2008. This transaction will contribute immediate revenue and cash flow and position Husky to move forward with the development of the Sunrise oil sands project.

In December 2007, Husky agreed to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central region of the Athabasca oil sands deposit, for $105 million. This land lies adjacent to oil sands leases currently held by Husky.

Offshore Canada's East Coast, Husky announced the signing of a binding agreement formalizing the fiscal terms for development of the North Amethyst, West White Rose and South White Rose fields. Under the agreement, the terms of the original White Rose development plan remain unchanged.

Offshore Greenland, Husky and Esso Exploration Greenland Limited ("Esso") were awarded a joint interest in an exploration licence in West Disko Block 6 (2007/27), which covers an area of 13,213 square kilometres and is located approximately 30 kilometres offshore the west coast of Disko Island. Esso will act as operator of this block. In addition, Husky has an 87.5% interest in two exploration licences, Block 5 and Block 7, covering an area of 21,067 square kilometres that border on Licence 2007/27. Nunaoil A/S, Greenland's National Oil Company, holds the remaining 12.5% interest in these three licences.

In Indonesia, Husky completed the gas sale and purchase agreements for production from the Madura BD Field. Agreements with PT Parna Raya and PT Inti Alasindo Energy are each for 40 million cubic feet per day while the agreement with PT Perusahaan Gas Negara (Persero) Tbk is for 20 million cubic feet per day. The term of each agreement is 20 years commencing with first production, which is expected in 2011.

Husky has submitted a plan of development to the Government of Indonesia for the Madura development and is in the process of negotiating an extension to the Madura Strait Production Sharing Contract. Contracting for front-end engineering design of offshore facilities and pipelines will commence shortly.

In the Downstream segment, Husky has now completed its integration of the Lima refinery and has taken over all major operations effective February 1, 2008. At the Lima refinery, Husky has commenced its engineering studies to determine the optimal reconfiguration to process a heavier crude oil feedstock.

In the fourth quarter of 2007, Husky completed construction and commenced production at the Minnedosa ethanol plant in Manitoba. The facility will produce annually 130 million litres of ethanol and 130,000 tonnes of Distillers Dried Grain with Solubles (DDGS), a high protein feed supplement. With the completion of the ethanol plants at Lloydminster and Manitoba, Husky is the largest producer and marketer of ethanol in Western Canada.



SUMMARY OF RESULTS

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

(millions of dollars, Dec. 31 Sept. 30 June 30 March 31
except per share
amounts and ratios) 2007 2007 2007 2007
----------------------------------------------------------
Sales and operating
revenues, net of
royalties $ 4,760 $ 4,351 $ 3,163 $ 3,244
Segmented earnings
Upstream $ 864 $ 516 $ 636 $ 580
Midstream 218 129 77 111
Downstream 103 121 53 20
Corporate and
eliminations (111) 3 (45) (61)
----------------------------------------------------------
Net earnings $ 1,074 $ 769 $ 721 $ 650
----------------------------------------------------------
----------------------------------------------------------
Per share - Basic
and diluted (1) $ 1.26 $ 0.91 $ 0.85 $ 0.77
Cash flow from
operations 1,425 1,420 1,257 1,324
Per share - Basic
and diluted (1) 1.68 1.67 1.48 1.56
Ordinary quarterly
dividend per common
share (1) 0.33 0.25 0.25 0.25
Special dividend
per common share (1) - - - 0.25
Total assets 21,697 20,718 17,969 17,781
Total long-term debt
including current
portion 2,814 2,835 1,423 1,527
Return on equity (2)
(percent) 30.2 26.6 27.1 32.1
Return on average
capital employed (2)
(percent) 25.7 22.3 23.8 27.3
----------------------------------------------------------
----------------------------------------------------------

Three months ended Year ended

(millions of dollars, Dec. 31 Sept. 30 June 30 March 31 December 31
except per share
amounts and ratios) 2006 2006 2006 2006 2007 2006
----------------------------------------------------------------------------
Sales and operating
revenues, net of
royalties $ 3,084 $ 3,436 $ 3,040 $ 3,104 $15,518 $12,664
Segmented earnings
Upstream $ 453 $ 608 $ 822 $ 412 $ 2,596 $ 2,295
Midstream 105 87 140 150 535 482
Downstream 10 28 52 16 297 106
Corporate and
eliminations (26) (41) (36) (54) (214) (157)
----------------------------------------------------------------------------
Net earnings $ 542 $ 682 $ 978 $ 524 $ 3,214 $ 2,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per share - Basic
and diluted (1) $ 0.64 $ 0.80 $ 1.15 $ 0.62 $ 3.79 $ 3.21
Cash flow from
operations 1,207 1,224 1,103 967 5,426 4,501
Per share - Basic
and diluted (1) 1.42 1.44 1.30 1.14 6.39 5.30
Ordinary quarterly
dividend per
common share (1) 0.25 0.25 0.125 0.125 1.08 0.75
Special dividend per
common share (1) - - - - 0.25 -
Total assets 17,933 17,324 16,326 15,855 21,697 17,933
Total long-term debt
including current
portion 1,611 1,722 1,722 1,838 2,814 1,611
Return on equity (2)
(percent) 31.8 34.2 34.8 29.6 30.2 31.8
Return on average
capital employed (2)
(percent) 27.0 28.7 28.2 23.2 25.7 27.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Reflects a two-for-one share split on June 27, 2007, which has been
applied retroactively. Refer to Note 11 to the Consolidated Financial
Statements.
(2) Calculated for the 12 months ended for the dates shown.


Daily Gross Production
Three months ended

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

2007 2007 2007 2007 2006
----------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Western Canada
Light crude oil & NGL 25.8 25.1 25.3 30.1 30.4
Medium crude oil 27.0 26.7 26.8 27.5 28.0
Heavy crude oil & bitumen 107.8 106.5 105.4 108.0 109.5
----------------------------------------------------------------------------
160.6 158.3 157.5 165.6 167.9
East Coast Canada
White Rose - light crude oil 81.1 79.2 90.3 89.4 79.4
Terra Nova - light crude oil 11.6 16.3 15.5 14.7 6.7
China
Wenchang - light crude oil & NGL 11.2 12.7 13.2 13.6 11.7
----------------------------------------------------------------------------
264.5 266.5 276.5 283.3 265.7
----------------------------------------------------------------------------
Natural gas (mmcf/day) 617.8 620.1 615.7 640.0 662.2
----------------------------------------------------------------------------
Total (mboe/day) 367.5 369.9 379.1 390.0 376.1
----------------------------------------------------------------------------
----------------------------------------------------------------------------



2008 GUIDANCE AND 2007 ACTUAL

----------------------------------------------------------------------------
Gross Production Year ended Original
Guidance December 31 Guidance

2008 2007 2007
----------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Light crude oil & NGL 139-148 139 128-135
Medium crude oil 28- 29 27 28- 30
Heavy crude oil & bitumen 114-124 107 122-130
----------------------------------------------------------------------------
281-301 273 278-295
Natural gas (mmcf/day) 625-655 623 670-690
Total barrels of oil equivalent (mboe/day) 385-410 377 390-410
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Capital Program (1) Year ended Original
Guidance December 31 Guidance

2008 2007 2007
----------------------------------------------------------------------------
Upstream
Western Canada $ 1,670 $ 1,747 $ 1,840
Oil Sands 300 235 330
East Coast Canada and Frontier 650 279 290
International 430 73 160
----------------------------------------------------------------------------
3,050 2,334 2,620
Midstream 300 306 380
Downstream 300 223 140
Corporate 50 44 40
----------------------------------------------------------------------------
$ 3,700 $ 2,907 $ 3,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized administration costs, capitalized interest and
corporate acquisitions.

 


MAJOR PROJECTS

UPSTREAM

East Coast Canada Exploration and Delineation

- Production licences for the North Amethyst oil field southwest of White Rose and the South White Rose extension were received in late 2007.

- Delineation of the West White Rose area continued with the completion of the C-30Z well and in the North White Rose area with the completion of the K-03 delineation well.

White Rose and the White Rose Satellite Tie-back Project

- The White Rose South Avalon development plan was completed with the drilling of the second gas injection well in September.

- Front-end engineering design of the North Amethyst satellite tie-back was substantially complete as of December 31, 2007.

- Agreement was reached with the Government of Newfoundland and Labrador regarding fiscal terms for the White Rose satellite fields, including the sale by Husky and its partner of a 5% equity interest to the government.

- The Company has secured the Transocean owned mobile semi-submersible drilling unit GSF Grand Banks for ongoing operations in the White Rose area and for continued exploration and delineation drilling offshore Newfoundland and Labrador. The three year agreement has provisions for two additional one year contract extensions. The GSF Grand Banks has drilled 18 development wells for the White Rose project and has been drilling in offshore Newfoundland and Labrador since 2002.

Tucker Oil Sands Project

The Tucker oil sands project production ramp up has been slower than anticipated largely due to the position of some wells relative to the oil saturation in the reservoir. While optimization strategies are continuing on the original 32 well pairs, the drilling of eight new well pairs on Pad C is complete and a new D pad of eight well pairs is planned.

Sunrise Oil Sands Project

The front-end engineering design for the Sunrise project is complete. Discussions with regulatory authorities to amend our development application is proceeding. Corporate sanction is expected to be in 2008.

The plan for the Sunrise Oil Sands Partnership with BP will proceed in three phases. The first phase will target 60 mbbls/day of bitumen production in 2012. Production is scheduled to reach 200 mbbls/day of bitumen in the 2015 to 2020 period. Preliminary field work is progressing.

Caribou

The overall front-end engineering design has been finalized for the 10 mbbls/day demonstration project and additional technical work is ongoing. Discussions with regulatory authorities are expected to continue into 2008.

Saleski

The winter drilling program has been reduced from 12 to six wells. We are continuing to work on reservoir characterization and assess the technical merit of various recovery processes.

McMullen Oil Sands Acquisition

In December 2007, we executed an agreement to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central Athabasca oil sands deposit, for $105 million. This land lies adjacent to oil sands leases that we currently hold. We will have a 100% working interest in these oil sands leases.

Northwest Territories Exploration

Preparation for winter drilling on Exploration License ("EL") 423 in the Central Mackenzie Valley is currently underway. EL 423 is located approximately 60 kilometres southeast of the Summit Creek B-44 and the Stewart Creek D-57 discovery wells. The Dahadinni B-20 well is scheduled to commence drilling in early February and the Keele River L-52 well in mid-February with a second rig. Following the acquisition of additional interests from our partners earlier in 2007, we now hold a 75% working interest in this play.

China Exploration

The seismic program over Block 29/26 in the South China Sea, including the Liwan natural gas discovery, was 92% completed but then suspended due to bad weather at the end of October 2007. Delineation drilling of the Liwan area is expected to commence in the second half of 2008 upon the arrival of the West Hercules deep water drilling rig, which is currently being constructed in Korea.

In the shallow waters of East and South China seas, three exploration wells are planned for 2008. The first well is expected to spud in late February on Block 23/15 in the Beibu Wan Basin north of Hainan Island.

Indonesia Natural Gas Development and Exploration

The Plan of Development and production sharing licence extension were submitted to BPMIGAS and MIGAS, the Indonesian regulatory authorities, for approval. On the East Bawean II block we completed the acquisition of 1,400 square kilometres of 3-D seismic data.

Offshore Greenland

Our work programs for 2008 have been finalized and consist of the acquisition of 3,000 kilometres of 2D seismic over Block 6 and 7,000 kilometres of 2D seismic over blocks 5 and 7. Acquisition of the remainder of the hi-resolution aero-gravity and magnetic survey, which was stopped by severe weather conditions, will resume in May 2008.

MIDSTREAM

Lloydminster Pipeline

The Lloydminster to Hardisty, Alberta pipeline expansion project phase one is complete and operational. Phase two is complete and operational with the exception of an 11 kilometre section in and around the City of Lloydminster.

Lloydminster Upgrader

The expansion of the Lloydminster upgrader to 150,000 from 82,000 barrels per day has been deferred due to labour shortages and high costs.

DOWNSTREAM

Lima, Ohio Refinery

Engineering evaluation of several options to reconfigure the Lima, Ohio refinery to increase its capacity to process heavy oil feedstock is underway.

Minnedosa Ethanol Plant

The ethanol plant at Minnedosa, Manitoba, was commissioned in early December 2007. The completion of this plant increases our capacity to produce fuel grade ethanol to 260 million litres per year.



BUSINESS ENVIRONMENT

Husky's financial results are significantly influenced by its business
environment. Average quarterly market prices were:

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

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

2007 2007 2007 2007 2006
----------------------------------------------------------------------------
WTI crude oil(1) (U.S. $/bbl) 90.68 75.38 65.03 58.16 60.21
Brent crude oil(2) (U.S. $/bbl) 88.70 74.87 68.76 57.75 59.68
Canadian light
crude 0.3% sulphur ($/bbl) 87.19 80.70 72.61 67.76 65.12
Lloyd heavy crude
oil @ Lloydminster ($/bbl) 42.03 43.61 39.02 38.25 35.24
NYMEX natural gas(1) (U.S. $/mmbtu) 6.97 6.16 7.55 6.77 6.56
NIT natural gas ($/GJ) 5.69 5.31 6.99 7.07 6.03
WTI/Lloyd crude
blend differential (U.S. $/bbl) 34.06 23.50 20.36 17.32 21.75
U.S./Canadian dollar
exchange rate (U.S. $) 1.018 0.957 0.911 0.854 0.878
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.

 


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 fourth 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
Fourth
Quarter Effect on Pre-tax Effect on
Average Increase Cash Flow (6) Net Earnings (6)
----------------------------------------------------------------------------

($/ ($/
($ share) ($ share)
millions) (7) millions) (7)
Upstream and Midstream
WTI benchmark
crude oil price $90.68 U.S. $1.00/bbl 79 0.09 55 0.06
NYMEX benchmark
natural gas
price (1) $ 6.97 U.S. $0.20/mmbtu 31 0.04 22 0.03
WTI/Lloyd crude
blend
differential (2) $34.06 U.S. $1.00/bbl (22) (0.03) (15) (0.02)
Exchange rate
(U.S. $ per
Cdn $) (3) $1.018 U.S. $0.01 (73) (0.09) (52) (0.06)

Downstream
Light oil margins $ 0.04 Cdn $0.005/litre 16 0.02 10 0.01
Asphalt margins $11.62 Cdn $1.00/bbl 9 0.01 6 0.01
New York Harbor
3:2:1 crack
spread (4) $ 8.25 U.S. $1.00/bbl 54 0.06 34 0.04

Consolidated
Period end
translation of
U.S. $ debt
(U.S. $ per
Cdn $) $1.012(5) U.S. $0.01 18 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes decrease in earnings related to natural gas consumption.
(2) Includes impact of upstream and midstream upgrading operations only.
(3) Assumes no foreign exchange gains or losses on U.S. dollar denominated
long-term debt and other monetary items.
(4) Relates to the Lima, Ohio refinery that was acquired on July 1, 2007.
(5) U.S./Canadian dollar exchange rate at December 31, 2007.
(6) Excludes derivatives.
(7) Based on 849.0 million common shares outstanding as of December 31,
2007.


RESULTS OF OPERATIONS

UPSTREAM
----------------------------------------------------------------------------
Upstream Earnings Summary Three months Year ended
ended Dec. 31 Dec. 31

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross revenues $ 1,893 $ 1,619 $ 7,287 $ 6,586
Royalties 325 185 1,065 814
----------------------------------------------------------------------------
Net revenues 1,568 1,434 6,222 5,772
Operating and administration expenses 371 373 1,409 1,321
Depletion, depreciation and amortization 396 389 1,615 1,476
Other (13) - (101) -
Income taxes (50) 219 703 680
----------------------------------------------------------------------------
Earnings $ 864 $ 453 $ 2,596 $ 2,295
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Fourth Quarter

Upstream earnings in the fourth quarter of 2007 increased by $411 million compared with the fourth quarter of 2006 mainly as a result of a recovery of future tax expense due to federal rate reductions and higher sales volumes and light crude oil prices from White Rose and Terra Nova.

Twelve Months

Upstream earnings were $301 million higher in 2007 than in 2006 as a result of higher sales volumes of light crude oil from White Rose and Terra Nova and higher crude oil prices offset by lower sales volumes of crude oil and natural gas and lower natural gas prices in Western Canada.

Commodity Prices

The average prices realized during the fourth quarter and twelve months of 2007 compared with the fourth quarter and twelve months of 2006 are illustrated below.



----------------------------------------------------------------------------
Average Sales Prices Three months Year ended
ended Dec. 31 Dec. 31

2007 2006 2007 2006
----------------------------------------------------------------------------
Crude Oil ($/bbl)
Light crude oil & NGL 83.43 62.55 73.54 69.06
Medium crude oil 55.37 43.99 51.12 49.48
Heavy crude oil & bitumen 41.13 35.46 40.19 39.92
Total average 63.34 49.43 58.24 54.08
Natural Gas ($/mcf)
Average 5.72 6.19 6.19 6.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Unit Operating Costs

Unit operating costs were 1% higher in the fourth quarter of 2007 compared with the same period in 2006.

Unit Depletion, Depreciation and Amortization

Unit depletion, depreciation and amortization expense increased 4% in the fourth quarter of 2007 compared with the same period in 2006 due to a higher capital base and lower reserves used in the depletion calculation.

Other

During the fourth quarter of 2007, a $13 million gain, $101 million gain year-to-date, was recorded 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.




Netback Analysis Three months Year ended
ended Dec. 31 Dec. 31
2007 2006 2007 2006
----------------------------------------------------------------------------
$ % $ % $ % $ %
(1) (1) (1) (1)
Western Canada
Crude oil (per boe) (2)
Light crude oil
Gross price 66.38 53.72 61.02 59.84
Royalties 11.94 18 7.25 13 7.87 13 7.34 12
----------------------------------------------------------------------------
Net sales price 54.44 46.47 53.15 52.50
Operating costs (3) 15.04 23 15.92 30 13.24 22 11.89 20
----------------------------------------------------------------------------
39.40 30.55 39.91 40.61
----------------------------------------------------------------------------
Medium crude oil
Gross price 54.25 43.84 50.42 48.97
Royalties 9.78 18 7.40 17 8.89 18 8.61 18
----------------------------------------------------------------------------
Net sales price 44.47 36.44 41.53 40.36
Operating costs (3) 14.48 27 15.42 35 13.92 28 13.09 27
----------------------------------------------------------------------------
29.99 21.02 27.61 27.27
----------------------------------------------------------------------------
Heavy crude oil & bitumen
Gross price 41.02 35.53 40.14 39.91
Royalties 5.83 14 4.49 13 5.26 13 5.16 13
----------------------------------------------------------------------------
Net sales price 35.19 31.04 34.88 34.75
Operating costs (3) 13.63 33 12.10 34 12.81 32 11.10 28
----------------------------------------------------------------------------
21.56 18.94 22.07 23.65
----------------------------------------------------------------------------
Natural gas (per mcfge) (4)
Gross price 6.17 6.32 6.42 6.65
Royalties 1.16 19 1.20 19 1.23 19 1.37 21
----------------------------------------------------------------------------
Net sales price 5.01 5.12 5.19 5.28
Operating costs (3) 1.41 23 1.39 22 1.39 22 1.18 18
----------------------------------------------------------------------------
3.60 3.73 3.80 4.10
----------------------------------------------------------------------------
East Coast
Light crude oil (per boe) (2)
Gross price 85.31 64.62 75.37 71.18
Royalties (5) 14.46 17 1.96 3 9.43 13 1.95 3
----------------------------------------------------------------------------
Net sales price 70.85 62.66 65.94 69.23
Operating costs (3) 3.91 5 4.14 6 4.07 5 5.48 8
----------------------------------------------------------------------------
66.94 58.52 61.87 63.75
----------------------------------------------------------------------------
Canada
Crude oil equivalent
(per boe) (2)
Gross price 54.10 45.17 51.54 48.48
Royalties 9.11 17 5.17 11 7.46 14 6.00 12
----------------------------------------------------------------------------
Net sales price 44.99 40.00 44.08 42.48
Operating costs (3) 9.78 18 9.76 22 9.28 18 9.01 19
----------------------------------------------------------------------------
35.21 30.24 34.80 33.47
----------------------------------------------------------------------------
International
Light crude oil (per boe) (2)
Gross price 89.17 66.01 77.07 73.60
Royalties 24.14 27 10.57 16 15.50 20 12.17 17
----------------------------------------------------------------------------
Net sales price 65.03 55.44 61.57 61.43
Operating costs (3) 4.25 5 4.90 7 3.84 5 3.81 5
----------------------------------------------------------------------------
60.78 50.54 57.73 57.62
----------------------------------------------------------------------------
Total
Crude oil equivalent
(per boe) (2)
Gross price 55.20 45.83 52.41 49.34
Royalties 9.58 17 5.32 11 7.74 15 6.19 12
----------------------------------------------------------------------------
Net sales price 45.62 40.51 44.67 43.15
Operating costs (3) 9.61 18 9.51 21 9.09 17 8.77 18
----------------------------------------------------------------------------
36.01 31.00 35.58 34.38
DD&A 11.71 21 11.23 25 11.75 22 11.24 23
Administration expenses
& other (3) 0.22 - 0.34 1 (0.17) - 0.48 1
----------------------------------------------------------------------------
Earnings before income taxes 24.08 44 19.43 42 24.00 46 22.66 46
----------------------------------------------------------------------------
100 100 100 100
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Percent of gross price.
(2) Includes associated co-products converted to boe.
(3) Operating costs exclude accretion, which is included in administration
expenses & other.
(4) Includes associated co-products converted to mcfge.
(5) During the third quarter of 2007, White Rose royalties increased to 16%
because the project, off the East Coast, achieved payout status for Tier
1 royalties.


Upstream Capital Expenditures Summary (1) Three months Year ended
ended Dec. 31 Dec. 31

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
Exploration
Western Canada $ 118 $ 37 $ 456 $ 497
East Coast Canada and Frontier 51 38 84 79
International 24 8 70 77
----------------------------------------------------------------------------
193 83 610 653
----------------------------------------------------------------------------
Development
Western Canada 476 593 1,575 1,675
East Coast Canada 36 28 197 279
International 1 - 6 20
----------------------------------------------------------------------------
513 621 1,778 1,974
----------------------------------------------------------------------------
$ 706 $ 704 $ 2,388 $ 2,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period.

Western Canada Wells Drilled Three months Year ended
ended Dec. 31 Dec. 31

2007 2006 2007 2006

Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Exploration Oil 23 23 30 29 79 79 101 99
Gas (1) 29 20 52 42 114 92 330 192
Dry 1 - 2 2 14 12 26 24
----------------------------------------------------------------------------
53 43 84 73 207 183 457 315
----------------------------------------------------------------------------
Development Oil 154 143 210 209 571 530 590 543
Gas (1) 102 56 183 159 343 251 565 490
Dry 12 10 5 5 31 29 25 22
----------------------------------------------------------------------------
268 209 398 373 945 810 1,180 1,055
----------------------------------------------------------------------------
Total 321 252 482 446 1,152 993 1,637 1,370
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The decrease in the number of gas wells drilled for the year ended
December 31, 2007 compared with 2006 reflects weaker gas prices and a
fall in the number of coalbed methane wells.

MIDSTREAM
----------------------------------------------------------------------------
Upgrading Earnings Summary Three months Year ended
ended Dec. 31 Dec. 31
(millions of dollars,
except where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin $ 232 $ 145 $ 614 $ 624
Operating costs 61 55 221 224
Other recoveries (1) (2) (4) (6)
Depreciation and amortization 8 6 25 24
Income taxes 27 27 90 97
----------------------------------------------------------------------------
Earnings $ 137 $ 59 $ 282 $ 285
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Upgrader throughput (1) (mbbls/day) 73.1 70.8 61.4 71.0
Synthetic crude oil sales (mbbls/day) 66.5 64.1 53.1 62.5
Upgrading differential ($/bbl) $ 36.74 $ 23.81 $ 30.73 $ 26.16
Unit margin ($/bbl) $ 37.92 $ 24.57 $ 31.67 $ 27.35
Unit operating cost (2) ($/bbl) $ 8.95 $ 8.39 $ 9.83 $ 8.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.

 


Fourth Quarter

Upgrading earnings in the fourth quarter of 2007 were $78 million higher than the fourth quarter of 2006 due to an increased upgrading differential, higher sales volume of synthetic crude oil and a recovery of future tax expense due to federal rate reductions.

Twelve Months

Upgrading earnings in 2007 were $3 million less than 2006 largely due to lower sales volumes due to the 49-day plant turnaround offset by an increase in the upgrading differential.



----------------------------------------------------------------------------
Infrastructure and Marketing Three months Year ended
Earnings Summary ended Dec. 31 Dec. 31
(millions of dollars,
except where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin - pipeline $ 28 $ 24 $ 115 $ 104
- other infrastructure
and marketing 87 56 278 208
----------------------------------------------------------------------------
115 80 393 312
Other expenses 7 3 14 11
Depreciation and amortization 7 7 28 24
Income taxes 20 24 98 80
----------------------------------------------------------------------------
Earnings $ 81 $ 46 $ 253 $ 197
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline throughput (mbbls/day) 497 465 501 475
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Fourth Quarter

Infrastructure and marketing earnings in the fourth quarter of 2007 increased by $35 million over the same period in 2006 primarily due to higher earnings from sales of blended heavy crude oil, higher crude oil and NGL trading earnings and a recovery of future tax expense due to federal rate reductions.

Twelve Months

Infrastructure and marketing earnings in 2007 increased by $56 million over 2006 primarily due to higher crude oil pipeline margins, higher crude oil and NGL trading earnings, higher earnings from sales of blended heavy crude oil and higher natural gas marketing earnings.

Midstream Capital Expenditures

Midstream capital expenditures totalled $309 million in 2007; $217 million at the Lloydminster Upgrader, primarily for debottleneck and reliability projects and expansion studies and $92 million on pipelines and infrastructure.



DOWNSTREAM
----------------------------------------------------------------------------
Canadian Refined Products Three months Year ended
Earnings Summary ended Dec. 31 Dec. 31
(millions of dollars,
except where indicated) 2007 2006 2007 2006
----------------------------------------------------------------------------
Gross margin - fuel sales $ 44 $ 17 $ 188 $ 138
- ancillary sales 11 10 42 36
- asphalt sales 29 23 160 94
----------------------------------------------------------------------------
84 50 390 268
Operating and other expenses 25 21 82 74
Depreciation and amortization 19 14 66 48
Income taxes (12) 5 50 40
----------------------------------------------------------------------------
Earnings $ 52 $ 10 $ 192 $ 106
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Number of fuel outlets 505 505
Light oil sales (million litres/day) 8.5 8.6 8.7 8.7
Light oil retail sales per outlet
(thousand litres/day) 13.4 12.8 13.2 12.9
Prince George refinery throughput
(mbbls/day) 11.6 11.2 10.5 9.0
Asphalt sales (mbbls/day) 24.5 21.0 21.8 23.4
Lloydminster refinery throughput
(mbbls/day) 28.8 28.1 25.3 27.1
Ethanol production (thousand litres/day) 347.2 159.3 324.6 59.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Fourth Quarter

Canadian refined products earnings in the fourth quarter of 2007 increased by $42 million over the fourth quarter of 2006 due to higher margins for gasoline and ethanol, higher sales volume for asphalt products and a recovery of future tax expense due to federal rate reductions.

Twelve Months

Canadian refined products earnings in 2007 increased by $86 million over 2006 due to higher margins for gasoline, distillates, ethanol and asphalt and higher sales volume of ethanol products partially offset by higher depreciation created by the startup of the Lloydminster ethanol plant.



----------------------------------------------------------------------------
U.S. Refining and Marketing Earnings Summary Three months Six months
ended Dec. 31 ended Dec. 31

(millions of dollars, except where indicated) 2007 2007
----------------------------------------------------------------------------
Gross refining margin $ 155 $ 310
Processing costs 48 93
Operating and other expenses 1 1
Interest - net - 1
Depreciation and amortization 25 47
Income taxes 30 63
----------------------------------------------------------------------------
Earnings $ 51 $ 105
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Refinery throughput (mbbls/day)
Crude oil and other feedstock 147 144
Yield (mbbls/day)
Gasoline 84 82
Middle distillates 52 47
Other fuel and feedstock 13 16
Margins ($/bbl crude throughput)
Gross refining margin 11.12 12.42
Unit operating costs ($/bbl of yield) 3.47 3.48
Refined product sales (mbbls/day)
Gasoline 87 81
Middle distillates 52 46
Other fuel and feedstock 14 13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


The Lima refinery had a good fourth quarter meeting expectations and operating normally following the electrical transformer outage in the third quarter.

Downstream Capital Expenditures

Canadian refined products capital expenditures totalled $212 million in 2007; $3 million at the Lloydminster ethanol plant, $114 million at the Minnedosa ethanol plant, $69 million for marketing location upgrades and construction, $17 million for debottleneck and upgrade projects at the Lloydminster asphalt refinery and asphalt distribution facilities and $9 million at the Prince George refinery.

Subsequent to the acquisition of the Lima refinery, capital expenditures at the refinery for the six months ended December 31, 2007 totalled $21 million and were largely for environmental projects and plant upgrades to improve reliability.



CORPORATE
----------------------------------------------------------------------------
Corporate Summary Three months Year ended
ended Dec. 31 Dec. 31

(millions of dollars) income (expense) 2007 2006 2007 2006
----------------------------------------------------------------------------
Intersegment eliminations - net $ (16) $ 36 $ (51) $ 20
Administration expenses (21) (16) (54) (35)
Stock-based compensation (40) (35) (88) (138)
Accretion - (1) (4) (3)
Other - net 6 (4) (5) (23)
Depreciation and amortization (7) (10) (25) (27)
Interest on debt (46) (27) (148) (125)
Interest capitalized 6 3 19 33
Foreign exchange - realized (32) (12) (74) 7
Foreign exchange - unrealized 26 4 125 17
Income taxes 13 36 91 117
----------------------------------------------------------------------------
Earnings (loss) $ (111) $ (26) $ (214) $ (157)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Foreign Exchange Summary Three months Year ended
ended Dec. 31 Dec. 31

(millions of dollars) 2007 2006 2007 2006
----------------------------------------------------------------------------
(Gain) loss on translation of U.S.
dollar denominated long-term debt
Realized $ - $ (11) $ - $ (42)
Unrealized (9) 71 (197) 35
----------------------------------------------------------------------------
(9) 60 (197) (7)
----------------------------------------------------------------------------
Cross currency swaps
Realized - 47 - 47
Unrealized 3 (69) 62 (43)
----------------------------------------------------------------------------
3 (22) 62 4
----------------------------------------------------------------------------
Other (gains) losses 12 (30) 84 (21)
----------------------------------------------------------------------------
$ 6 $ 8 $ (51) $ (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S./Canadian dollar exchange rates:
At beginning of period U.S. U.S. U.S. U.S.
$ 1.004 $ 0.897 $ 0.858 $ 0.858
At end of period U.S. U.S. U.S. U.S.
$ 1.012 $ 0.858 $ 1.012 $ 0.858
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Corporate Capital Expenditures

Corporate capital expenditures totalled $44 million in 2007 primarily for
various office and information system upgrades.


ADDITIONAL INFORMATION
OIL AND GAS RESERVES
----------------------------------------------------------------------------
Reconciliation of Proved Reserves (1)

Crude oil
& NGL Natural gas Equivalent units
(mmbbls) (bcf) (mmboe)
----------------------------------------------------------------------------
December 31, 2006 647 2,143 1,004
Revision of previous estimates 25 64 36
Discoveries, extensions and
improved recovery 85 199 118
Purchase of reserves in place 1 36 7
Sale of reserves in place (10) (23) (14)
Production (99) (228) (137)
----------------------------------------------------------------------------
December 31, 2007 649 2,191 1,014
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Proved plus probable reserves
December 31, 2007 2,688 3,180 3,218
December 31, 2006 2,006 2,626 2,444
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Constant price before royalties.

 


NON-GAAP MEASURES

Disclosure of Cash Flow from Operations

This document 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:
----------------------------------------------------------------------------

Year ended December 31

(millions of dollars) 2007 2006
----------------------------------------------------------------------------
Non-GAAP Cash flow from operations $ 5,426 $ 4,501
Settlement of asset retirement obligations (51) (36)
Change in non-cash working capital (718) 544
----------------------------------------------------------------------------
GAAP Cash flow - operating activities $ 4,657 $ 5,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 Includes capitalized administrative expenses and
capitalized interest but does not include proceeds
or other assets
Capital Program Capital expenditures not including capitalized
administrative expenses or capitalized interest
Carbonate Sedimentary rock primarily composed of calcium
carbonate (limestone) or calcium magnesium carbonate
(dolomite) which forms many petroleum reservoirs
Cash Flow from Earnings from operations plus non-cash charges
Operations 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, retained earnings and accumulated other
comprehensive income
Feedstock Raw materials which are processed into petroleum
products
Front-end Engineering Preliminary engineering and design planning, which
Design among other things, identifies project objectives,
scope, alternatives, specifications, risks, costs,
schedule and economics
Glory Hole An excavation in the seabed where the wellheads and
other equipment are situated to protect them from
scouring icebergs
Gross/Net Acres/Wells Gross refers to the total number of acres/wells in
which an interest is owned. Net refers to the sum of
the fractional working interests owned by a company
Gross Reserves/ A company's working interest share of reserves/
Production production before deduction of royalties
Heads of Agreement A non-binding document that outlines the main issues
relevant to a tentative formal agreement
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 Exchange or transfer of title of gas that has been
Transfer received into the NOVA pipeline system but not yet
delivered to a connecting pipeline
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

 


FORWARD-LOOKING STATEMENTS OR INFORMATION

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: the closing of our joint venture agreement with BP, the throughput restriction at White Rose and East Coast seismic acquisition, our production plans for the Tucker in-situ oil sands project, our Sunrise and Caribou oil sands project production plans and development application schedule, our Northwest Territories drilling program, the schedule of our offshore China geophysical and drilling programs, the commencement of production at the Madura BD natural gas and NGL field, the timing for contracting front-end engineering design work for Indonesia, our Minnedosa plant production capability, our work programs for offshore Greenland 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. 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.

CAUTIONARY NOTE REQUIRED BY NATIONAL INSTRUMENT 51-101

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

Husky's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Husky by Canadian securities regulatory authorities, which permits Husky to provide disclosure required by and consistent with the requirements of the United States Securities and Exchange Commission and the Financial Accounting Standards Board in the United States in place of much of the disclosure expected by National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer to "Disclosure of Exemption Under National Instrument 51-101" on page 2 of our Annual Information Form for the year ended December 31, 2006 filed with securities regulatory authorities for further information.

The Company has disclosed contingent resources of bitumen in this news release. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingencies may include factors such as satisfactory drilling and testing results, adequate economic and market considerations and commitment to develop these resources as well as other factors such as legal, environmental, political and regulatory issues. There is no certainty that it will be commercially viable to produce any portion of these resources.

Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or lack of market. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.

CAUTIONARY NOTE TO U.S. INVESTORS

The United States Securities and Exchange Commission permits U.S. oil and gas companies, in their filings with the SEC, to disclose only proved reserves, that is reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. We use certain terms in this release, such as "probable reserves," "possible reserves," "discovered resource" and "contingent resource," that the SEC's guidelines strictly prohibit in filings with the SEC by U.S. oil and gas companies. U.S. investors should refer to our Annual Report on Form 40-F available from us or the SEC for further reserve disclosure.



CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
----------------------------------------------------------------------------
December 31 December 31
(millions of dollars, except share data) 2007 2006
----------------------------------------------------------------------------
(unaudited)
Assets
Current assets
Cash and cash equivalents $ 208 $ 442
Accounts receivable 1,622 1,284
Inventories 1,190 428
Prepaid expenses 28 25
----------------------------------------------------------------------------
3,048 2,179
Property, plant and equipment - (full cost
accounting) 29,407 25,552
Less accumulated depletion, depreciation and
amortization 11,602 10,002
----------------------------------------------------------------------------
17,805 15,550
Goodwill 660 160
Other assets 184 44
----------------------------------------------------------------------------
$ 21,697 $ 17,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 2,358 $ 2,574
Long-term debt due within one year (note 7) 741 100
----------------------------------------------------------------------------
3,099 2,674
Long-term debt (note 7) 2,073 1,511
Other long-term liabilities (note 8) 918 756
Future income taxes (note 9) 3,957 3,372
Commitments and contingencies (note 10)
Shareholders' equity
Common shares (note 11) 3,551 3,533
Retained earnings 8,176 6,087
Accumulated other comprehensive income (77) -
----------------------------------------------------------------------------
11,650 9,620
----------------------------------------------------------------------------
$ 21,697 $ 17,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Common shares outstanding (millions) (note 11) 849.0 848.5
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.


Consolidated Statements of Earnings and Comprehensive Income
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
(millions of dollars, except share
data)
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Sales and operating revenues, net of
royalties $ 4,760 $ 3,084 $ 15,518 $ 12,664
Costs and expenses
Cost of sales and operating expenses 3,081 1,760 9,296 7,169
Selling and administration expenses 71 47 219 162
Stock-based compensation 40 35 88 138
Depletion, depreciation and
amortization 462 426 1,806 1,599
Interest - net (note 7) 40 24 130 92
Foreign exchange (note 7) 6 8 (51) (24)
Other - net (note 13) (16) 3 (97) 22
----------------------------------------------------------------------------
3,684 2,303 11,391 9,158
----------------------------------------------------------------------------
Earnings before income taxes 1,076 781 4,127 3,506
----------------------------------------------------------------------------
Income taxes
Current 110 54 347 678
Future (note 9) (108) 185 566 102
----------------------------------------------------------------------------
2 239 913 780
----------------------------------------------------------------------------
Net earnings 1,074 542 3,214 2,726
Other comprehensive income (note 3)
Derivatives designated as cash flow
hedges, net of tax (note 13) 10 - 14 -
Cumulative foreign currency
translation adjustment (35) - (175) -
Hedge of net investment, net of tax
(note 13) 11 - 102 -
----------------------------------------------------------------------------
(14) - (59) -
----------------------------------------------------------------------------
Comprehensive income (note 3) $ 1,060 $ 542 $ 3,155 $ 2,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Earnings per share
Basic and diluted (note 11) $ 1.26 $ 0.64 $ 3.79 $ 3.21
Weighted average number of common
shares outstanding (millions)
Basic and diluted (note 11) 849.0 848.5 848.8 848.4
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.


Consolidated Statements of Changes in Shareholders' Equity
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
(millions of dollars)
(unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Common shares
Beginning of period $ 3,549 $ 3,532 $ 3,533 $ 3,523
Options exercised 2 1 18 10
----------------------------------------------------------------------------
End of period 3,551 3,533 3,551 3,533
----------------------------------------------------------------------------
Retained earnings
Beginning of period 7,382 5,757 6,087 3,997
Net earnings 1,074 542 3,214 2,726
Dividends on common shares
Ordinary (280) (212) (917) (636)
Special - - (212) -
Adoption of financial instruments
(notes 3, 13) - - 4 -
----------------------------------------------------------------------------
End of period 8,176 6,087 8,176 6,087
----------------------------------------------------------------------------
Accumulated other comprehensive income
Beginning of period (63) - - -
Adoption of financial instruments
(notes 3, 13) - - (18) -
Other comprehensive income (note 3)
Derivatives designated as cash flow
hedges, net of tax (note 13) 10 - 14 -
Cumulative foreign currency
translation adjustment (35) - (175) -
Hedge of net investment, net of tax
(note 13) 11 - 102 -
----------------------------------------------------------------------------
(14) - (59) -
----------------------------------------------------------------------------
End of period (77) - (77) -
----------------------------------------------------------------------------
Shareholders' equity $ 11,650 $ 9,620 $ 11,650 $ 9,620
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.


Consolidated Statements of Cash Flows
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
(millions of dollars) (unaudited) 2007 2006 2007 2006
----------------------------------------------------------------------------
Operating activities
Net earnings $ 1,074 $ 542 $ 3,214 $ 2,726
Items not affecting cash
Accretion (note 8) 12 11 47 45
Depletion, depreciation and
amortization 462 426 1,806 1,599
Future income taxes (108) 185 566 102
Foreign exchange (8) 39 (135) (3)
Other (7) 4 (72) 32
Settlement of asset retirement
obligations (note 8) (16) (12) (51) (36)
Change in non-cash working capital
(note 5) 142 (89) (718) 544
----------------------------------------------------------------------------
Cash flow - operating activities 1,551 1,106 4,657 5,009
----------------------------------------------------------------------------
Financing activities
Bank operating loans financing - net (44) - - -
Long-term debt issue 600 - 7,222 1,226
Long-term debt repayment (601) (171) (5,722) (1,493)
Settlement of cross currency swap - (47) - (47)
Debt issue costs - - (8) -
Proceeds from exercise of stock
options 1 - 5 3
Dividends on common shares (280) (212) (1,129) (636)
Other - (1) - (1)
Change in non-cash working capital
(note 5) (292) (14) 65 (678)
----------------------------------------------------------------------------
Cash flow - financing activities (616) (445) 433 (1,626)
----------------------------------------------------------------------------
Available for investing 935 661 5,090 3,383
----------------------------------------------------------------------------
Investing activities
Capital expenditures (840) (882) (2,931) (3,171)
Corporate acquisition (note 4) - - (2,589) -
Asset sales 1 - 333 34
Other (2) - (44) (12)
Change in non-cash working capital
(note 5) 107 119 (93) 40
----------------------------------------------------------------------------
Cash flow - investing activities (734) (763) (5,324) (3,109)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents 201 (102) (234) 274
Cash and cash equivalents, beginning
of period 7 544 442 168
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period $ 208 $ 442 $ 208 $ 442
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.




Notes to the Consolidated Financial Statements
Year ended December 31, 2007 (unaudited)
Except where indicated, all dollar amounts are in millions.
Note 1 Segmented Financial Information


Upstream Midstream

Infrastructure
Upgrading and Marketing
2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Three months
ended December 31
Sales and
operating
revenues, net of
royalties $ 1,568 $ 1,434 $ 530 $ 385 $ 2,617 $ 2,377
Costs and
expenses
Operating, cost
of sales, selling
and general 358 373 358 293 2,509 2,300
Depletion,
depreciation and
amortization 396 389 8 6 7 7
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
754 762 366 299 2,516 2,307
----------------------------------------------------------------------------
Earnings (loss)
before income
taxes 814 672 164 86 101 70
Current income
taxes 41 62 5 (31) 18 22
Future income
taxes (91) 157 22 58 2 2
----------------------------------------------------------------------------
Net earnings
(loss) $ 864 $ 453 $ 137 $ 59 $ 81 $ 46
----------------------------------------------------------------------------
Capital expenditures -
Three months ended
Dec. 31 (2) $ 706 $ 704 $ 44 $ 65 $ 15 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Dec. 31
Sales and
operating
revenues, net of
royalties $ 6,222 $ 5,772 $1,524 $ 1,679 $ 10,217 $ 9,559
Costs and
expenses
Operating, cost
of sales, selling
and general 1,308 1,321 1,127 1,273 9,838 9,258
Depletion,
depreciation and
amortization 1,615 1,476 25 24 28 24
Interest - net - - - - - -
Foreign exchange - - - - - -
----------------------------------------------------------------------------
2,923 2,797 1,152 1,297 9,866 9,282
----------------------------------------------------------------------------
Earnings (loss)
before income taxes 3,299 2,975 372 382 351 277
Current income
taxes 122 519 10 53 68 79
Future income
taxes 581 161 80 44 30 1
----------------------------------------------------------------------------
Net earnings
(loss) $ 2,596 $ 2,295 $ 282 $ 285 $ 253 $ 197
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital expenditures -
Year ended Dec. 31 (2) $ 2,388 $ 2,627 $ 217 $ 184 $ 92 $ 68
Goodwill
additions - Year
ended Dec. 31 $ - $ - $ - $ - $ - $ -
Total assets - As
at Dec. 31 $14,395 $13,920 $1,405 $ 992 $ 1,134 $ 1,329
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Downstream Corporate and Total
Eliminations (1)
U.S.
Canadian Refining
Refined and
Products Marketing
2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
Three months
ended
December 31
Sales and
operating
revenues,
net of
royalties $ 758 $ 579 $1,340 $ - $(2,053) $(1,691) $ 4,760 $ 3,084
Costs and
expenses
Operating,
cost of
sales,
selling and
general 699 550 1,234 - (1,982) (1,671) 3,176 1,845
Depletion,
depreciation
and
amortization 19 14 25 - 7 10 462 426
Interest - net - - - - 40 24 40 24
Foreign
exchange - - - - 6 8 6 8
----------------------------------------------------------------------------
718 564 1,259 - (1,929) (1,629) 3,684 2,303
----------------------------------------------------------------------------
Earnings (loss)
before income
taxes 40 15 81 - (124) (62) 1,076 781
Current income
taxes 4 2 14 - 28 (1) 110 54
Future income
taxes (16) 3 16 - (41) (35) (108) 185
----------------------------------------------------------------------------
Net earnings
(loss) $ 52 $ 10 $ 51 $ - $ (111) $ (26) $ 1,074 $ 542
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital
expenditures
- Three months
ended Dec. 31
(2) $ 52 $ 83 $ 16 $ - $ 20 $ 14 $ 853 $ 893
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended
Dec. 31
Sales and
operating
revenues,
net of
royalties $ 2,916 $2,575 $2,383 $ - $(7,744) $(6,921) $15,518 $12,664
Costs and
expenses
Operating,
cost of
sales,
selling and
general 2,608 2,381 2,167 - (7,542) (6,742) 9,506 7,491
Depletion,
depreciation
and
amortization 66 48 47 - 25 27 1,806 1,599
Interest - net - - 1 - 129 92 130 92
Foreign exchange - - - - (51) (24) (51) (24)
----------------------------------------------------------------------------
2,674 2,429 2,215 - (7,439) (6,647) 11,391 9,158
----------------------------------------------------------------------------
Earnings (loss)
before income
taxes 242 146 168 - (305) (274) 4,127 3,506
Current income
taxes 17 19 28 - 102 8 347 678
Future income
taxes 33 21 35 - (193) (125) 566 102
----------------------------------------------------------------------------
Net earnings
(loss) $ 192 $ 106 $ 105 $ - $ (214) $ (157) $ 3,214 $ 2,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital
expenditures
- Year ended
Dec. 31 (2) $ 212 $ 285 $ 21 $ - $ 44 $ 37 $ 2,974 $ 3,201
Goodwill
additions -
Year ended
Dec. 31 $ - $ - $ 500 $ - $ - $ - $ 500 $ -
Total assets
- As at Dec.
31 $ 1,335 $1,114 $3,058 $ - $ 370 $ 578 $21,697 $17,933
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Eliminations relate to sales and operating revenues between segments
recorded at transfer prices based on current market prices, and to
unrealized intersegment profits in inventories.
(2) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.


Geographical Financial Information
----------------------------------------------------------------------------
Other
Canada United States International Total
2007 2006 2007 2006 2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months
ended
December 31
Sales and
operating
revenues,
net of
royalties $ 3,088 $ 2,694 $ 1,603 $ 330 $ 69 $ 60 $ 4,760 $ 3,084
Capital
expenditures
(1) 812 885 16 - 25 8 853 893

Year ended
December 31
Sales and
operating
revenues,
net of
royalties $11,736 $11,050 $ 3,494 $ 1,340 $ 288 $ 274 $15,518 $12,664
Capital
expenditures
(1) 2,877 3,104 21 - 76 97 2,974 3,201

As at
December 31
Property,
plant and
equipment,
net $16,017 $15,200 $ 1,417 $ 3 $ 371 $ 347 $17,805 $15,550
Goodwill (2) 160 160 500 - - - 660 160
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period and corporate acquisitions.
(2) Changes in goodwill for the U.S. arise from translation of goodwill in
our self-sustaining U.S. operations. Refer to note 4, Corporate
Acquisition.

 


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, if the Company elects to use hedge accounting, 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 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) Lima, Ohio Refinery Acquisition

As a result of the Lima, Ohio refinery acquisition, effective July 1, 2007, the following accounting policies have been implemented:

i) Financial Instruments and Hedging Activities - Net Investment Hedges

The Company may designate certain U.S. dollar denominated debt as a hedge of its net investment in self-sustaining foreign operations. The unrealized foreign exchange gains and losses arising from the translation of the debt are recorded in other comprehensive income, net of tax and are limited to the translation gain or loss on the net investment.

ii) Foreign Currency Translation

The accounts of self-sustaining foreign operations are translated using the current rate method. Assets and liabilities are translated at the period-end exchange rate and revenues and expenses are translated at the average exchange rates for the period. Gains and losses on the translation of self-sustaining foreign operations are included in a separate component of accumulated other comprehensive income.

iii) Precious Metals

The Company uses precious metals in conjunction with catalyst as part of the refining process at the Lima, Ohio refinery. These precious metals remain intact; however, there is a loss during the reclamation process. The estimated loss is amortized to operating expenses over the period that the precious metal is in use, which is approximately two to five years. After the reclamation process, the actual loss is compared to the estimated loss and any difference is recognized in earnings.

c) 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.

d) Inventories

In June 2007, the Canadian Accounting Standards Board ("AcSB") issued CICA section 3031, "Inventories," which replaces section 3030 of the same name. The new guidance provides additional measurement and disclosure requirements. Under the new guidance, the last-in, first-out ("LIFO") basis for determining cost will no longer be permitted and reversals of impairment write-downs, which are not currently allowable, will be required. Section 3031 is effective for the Company on January 1, 2008. The Company has assessed section 3031 and has determined that the adoption of this standard will not have an impact on the financial statements.

Note 4 Corporate Acquisition

Effective July 1, 2007, the Company acquired a refinery in Lima, Ohio from The Premcor Refining Group Inc., an indirect wholly owned subsidiary of Valero Energy Corporation through the purchase of all of the issued and outstanding shares of Lima Refining Company ("Lima"). The total cash consideration was U.S. $1.9 billion plus U.S. $540 million for the cost of feedstock and product inventory. The results of Lima are included in the consolidated financial statements of the Company from its acquisition date. The operations of Lima are a self-sustaining foreign operation for foreign currency translation purposes.

Prior to the acquisition of Lima, the Company's business was conducted through three major business segments - Upstream, Midstream and Refined Products. The Refined Products segment has been renamed "Downstream" and includes refining in Canada of crude oil and marketing of refined petroleum products including gasoline, diesel, ethanol blended fuels, asphalt and ancillary products (Canadian Refined Products) and refining in the U.S. of primarily light sweet crude oil to produce and market gasoline and diesel fuels that meet U.S. clean fuels standards (U.S. Refining and Marketing). The Lima operations have been included in the Downstream - U.S. Refining and Marketing segment in note 1, Segmented Financial Information.



The allocation of the aggregate purchase price based on the estimated fair
values of the net assets of Lima on its acquisition date was as follows:

----------------------------------------------------------------------------
U.S. $ Cdn $
----------------------------------------------------------------------------
Net assets acquired
Working capital $ 4 $ 4
Property, plant and equipment 1,455 1,542
Goodwill (1) 506 536
Other assets 25 26
Other long-term liabilities (86) (91)
----------------------------------------------------------------------------
1,904 2,017
Feedstock and product inventory acquired 540 572
----------------------------------------------------------------------------
Total $ 2,444 $ 2,589
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Allocated to U.S. Refining and Marketing in the Company's downstream
segment. For U.S. income tax purposes, goodwill is deductible and
amortized over a 15-year period. Refer to note 1, Segmented Financial
Information.

Note 5 Cash Flows - Change in Non-cash Working Capital

Three months Year ended
ended Dec. 31 Dec. 31
2007 2006 2007 2006
----------------------------------------------------------------------------
a) Change in non-cash working capital
was as follows:
Decrease (increase) in non-cash
working capital
Accounts receivable $ (281) $ (282) $ (345) $ (428)
Inventories (114) 9 (212) 43
Prepaid expenses 23 34 1 14
Accounts payable and accrued
liabilities 329 255 (190) 277
----------------------------------------------------------------------------
Change in non-cash working capital $ (43) $ 16 $ (746) $ (94)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities $ 142 $ (89) $ (718) $ 544
Financing activities (292) (14) 65 (678)
Investing activities 107 119 (93) 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Other cash flow information:
Cash taxes paid $ 61 $ 52 $ 926 $ 215
Cash interest paid 57 46 162 147
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Note 6 Bank Operating Loans

At December 31, 2007, the Company had unsecured short-term borrowing lines of credit with banks totalling $270 million (December 31, 2006 - $220 million). As at December 31, 2007 and 2006, there were no bank operating loans outstanding. As of December 31, 2007, letters of credit under these lines of credit totalled $73 million (December 31, 2006 - $19 million).



Note 7 Long-term Debt
----------------------------------------------------------------------------
December 31

Maturity 2007 2006 2007 2006
----------------------------------------------------------------------------
Cdn $ Amount U.S. $ Denominated
Long-term debt
Medium-term notes (1) 2009 $ 203 $ 200 $ - $ -
6.25% notes 2012 395 466 400 400
7.55% debentures 2016 198 233 200 200
6.20% notes 2017 296 - 300 -
6.15% notes 2019 296 350 300 300
8.90% capital securities 2028 223 262 225 225
6.80% notes 2037 445 - 450 -
Debt issue costs (2) (20) - - -
Unwound interest rate swaps
(3) 37 - - -
----------------------------------------------------------------------------
$ 2,073 $ 1,511 $ 1,875 $ 1,125
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt due within
one year
Bridge financing (4) 2008 $ 741 $ - $ 750 $ -
Medium-term notes 2007 - 100 - -
----------------------------------------------------------------------------
$ 741 $ 100 $ 750 $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 13, 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.

(4) The Company has the right to extend the maturity of the bridge financing
to June 26, 2009 by providing 30 days' notice.

 


In July 2007, the Company obtained short-term bridge financing from several banks to facilitate closing the acquisition of the Lima, Ohio refinery. The bridge financing provided U.S. $1.5 billion while the remaining funds required were drawn under existing credit facilities. On September 11, 2007, the Company refinanced U.S. $750 million of the bridge financing by issuing U.S. $300 million of 6.20% notes due September 15, 2017 and U.S. $450 million of 6.80% notes due September 15, 2037. This was the first offering by Husky under a base shelf prospectus dated September 21, 2006 filed with securities regulatory authorities in Canada and the United States. The notes are redeemable at the option of the Company at any time, subject to a make whole provision. Interest is payable semi-annually. The notes are unsecured and unsubordinated and rank equally with all of Husky's other unsecured and unsubordinated indebtedness.



Interest - net consisted of:
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Long-term debt $ 45 $ 30 $ 151 $ 130
Short-term debt 1 1 6 5
----------------------------------------------------------------------------
46 31 157 135
Amount capitalized (6) (3) (19) (33)
----------------------------------------------------------------------------
40 28 138 102
Interest income - (4) (8) (10)
----------------------------------------------------------------------------
$ 40 $ 24 $ 130 $ 92
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Foreign exchange consisted of:
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
2007 2006 2007 2006
----------------------------------------------------------------------------
(Gain) loss on translation of U.S. dollar
denominated long-term debt $ (9) $ 60 $ (197) $ (7)
Cross currency swaps 3 (22) 62 4
Other (gains) losses 12 (30) 84 (21)
----------------------------------------------------------------------------
$ 6 $ 8 $ (51) $ (24)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Note 8 Other Long-term Liabilities
Asset Retirement Obligations
Changes to asset retirement obligations were as follows:
----------------------------------------------------------------------------
Year ended
December 31

2007 2006
----------------------------------------------------------------------------
Asset retirement obligations at beginning of year $ 622 $ 557
Liabilities incurred 57 35
Liabilities disposed (13) (1)
Liabilities settled (51) (36)
Revisions - 22
Accretion 47 45
----------------------------------------------------------------------------
Asset retirement obligations at end of year $ 662 $ 622
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


At December 31, 2007, the estimated total undiscounted inflation-adjusted amount required to settle outstanding asset retirement obligations was $4.7 billion. These obligations will be settled based on the useful lives of the underlying assets, which currently extend an average of 30 years into the future. This amount has been discounted using credit-adjusted risk free rates ranging from 6.2% to 6.8%.

Note 9 Income Taxes

In the fourth quarter of 2007, a recovery of future income taxes resulted from recording a non-recurring tax benefit of $365 million that arose due to changes in the federal tax rates. The related federal tax legislation was substantively enacted by December 31, 2007. This benefit was in addition to a $30 million recovery that was recorded in the second quarter also related to a reduction in federal tax rates. In the second quarter of 2006, future income taxes included a tax benefit of $328 million that arose due to federal and provincial tax rate changes.

Note 10 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 11 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:
----------------------------------------------------------------------------
Year ended December 31

2007 2006
----------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
----------------------------------------------------------------------------
Balance at beginning of
year 848,537,018 $ 3,533 848,250,156 $ 3,523
Options exercised 423,292 18 286,862 10
----------------------------------------------------------------------------
Balance at December 31 848,960,310 $ 3,551 848,537,018 $ 3,533
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Stock Options

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

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



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

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

Year ended December 31

2007 2006
----------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
----------------------------------------------------------------------------
Outstanding, beginning of year 11,656 $ 16.40 14,570 $ 12.91
Granted 26,926 $ 41.65 1,804 $ 35.71
Exercised for common shares (423) $ 11.84 (287) $ 11.15
Surrendered for cash (5,147) $ 13.40 (3,902) $ 11.97
Forfeited (2,881) $ 40.41 (529) $ 21.41
----------------------------------------------------------------------------
Outstanding at December 31 30,131 $ 37.18 11,656 $ 16.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable at December 31 4,494 $ 14.09 4,463 $ 12.48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

December 31, 2007

Outstanding Options Options Exercisable
----------------------------------------------------------------------------
Weighted
Number Weighted Average Number Weighted
Range of of Average Contractual of Average
Exercise Options Exercise Life Options Exercise
Price (thousands) Prices (years) (thousands) Prices
----------------------------------------------------------------------------
$ 7.23 - $9.99 44 $ 7.26 - 44 $ 7.26
$ 10.00 - $10.99 27 $10.32 1 27 $10.32
$ 11.00 - $12.99 3,832 $11.74 1 3,832 $11.74
$ 13.00 - $19.99 130 $15.92 2 84 $15.39
$ 20.00 - $29.99 455 $26.17 3 205 $26.43
$ 30.00 - $39.99 1,258 $35.89 3 302 $36.46
$ 40.00 - $42.57 24,385 $41.65 4 - $ -
----------------------------------------------------------------------------
30,131 $37.18 4 4,494 $14.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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



Note 12 Employee Future Benefits

Total benefit costs recognized were as follows:
----------------------------------------------------------------------------
Three months Year ended
ended Dec. 31 Dec. 31
2007 2006 2007 2006
----------------------------------------------------------------------------
Employer current service cost $ 8 $ 8 $ 25 $ 21
Interest cost 4 2 11 9
Expected return on plan assets (3) (4) (10) (8)
Amortization of net actuarial losses - 3 4 3
----------------------------------------------------------------------------
$ 9 $ 9 $ 30 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


Note 13 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 January 1,
31, 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 December 31, 2007, the Company had the following third party offsetting physical purchase and sale natural gas contracts, which met the definition of a derivative instrument:



----------------------------------------------------------------------------
Volumes
(mmcf) Fair Value
----------------------------------------------------------------------------
Physical purchase contracts 32,930 $ 6
Physical sale contracts (32,930) $ (5)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


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 December 31, 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 $ 3
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


This contract has been recorded at fair value in other assets.

During 2007, the Company recognized a gain of less than $1 million (2006 - gain of $1 million) from interest rate risk management activities.

Embedded Derivative

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



Foreign Currency Risk Management

At December 31, 2007, the Company had a cash flow hedge using the following
cross currency debt swaps:

----------------------------------------------------------------------------
Canadian Interest Rate
Debt Swap Amount Equivalent Swap Maturity (percent) Fair Value
----------------------------------------------------------------------------
6.25% notes U.S. $ 150 $ 212 June 15, 2012 7.41 $ (75)
6.25% notes U.S. $ 75 $ 90 June 15, 2012 5.65 $ (13)
6.25% notes U.S. $ 50 $ 59 June 15, 2012 5.67 $ (8)
6.25% notes U.S. $ 75 $ 88 June 15, 2012 5.61 $ (11)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 


These contracts have been recorded at fair value in other long-term liabilities. The portion of the fair value of the derivative related to foreign exchange losses has been recorded in earnings to offset the foreign exchange on the translation of the underlying debt. The remaining loss of $5 million, net of tax of $2 million, has been included in other comprehensive income. At December 31, 2007, the balance in accumulated other comprehensive income was $14 million, net of tax of $7 million.

The Company enters into short-dated foreign exchange contracts to fix the exchange rate for conversion of U.S. dollars to Canadian dollars. During 2007, the impact of these contracts was a loss of $18 million (2006 - gain of $2 million).

The Company entered into forward purchases of U.S. dollars to partially offset the fluctuations in foreign exchange related to the contract for drilling services offshore China, which contains an embedded derivative. At December 31, 2007, the following foreign exchange transactions had been entered into:



----------------------------------------------------------------------------
Date Forward Purchases Canadian Equivalent Fair Value
----------------------------------------------------------------------------
October 5, 2007 U.S. $ 119 $ 117 $ 2
October 11, 2007 U.S. $ 119 $ 116 $ 2
October 29, 2007 U.S. $ 119 $ 115 $ 4
----------------------------------------------------------------------------
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These forward contracts have been recorded at fair value in accounts receivable and other assets and the resulting gain has been recorded in other expenses in the consolidated statement of earnings. In 2007, the impact was a gain of $8 million.

Effective July 1, 2007, the Company's U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the Company's net investment in the U.S. refining and marketing operations, which are considered self-sustaining. The unrealized foreign exchange gain of $102 million, net of tax of $19 million, arising from the translation of the debt is recorded in other comprehensive income.

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 December 31, 2007, no accounts receivable had been sold under the program (December 31, 2006 - nil).

Note 14 Proposed Transaction with BP

In December 2007, the Company entered into an arrangement to create a 50/50 integrated oil sands joint venture with BP Corporation North America Inc. ("BP"), consisting of upstream and downstream assets. Under the terms of the arrangement, Husky will contribute its Sunrise assets located in the Athabasca oil sands in northeast Alberta to an oil sands partnership and BP will contribute its Toledo refinery located in Ohio, USA to a U.S. joint venture entity. In accordance with Canadian GAAP, these joint entities will be accounted for using the proportionate consolidation method. The transaction is scheduled to close in the first quarter of 2008.

Husky Energy Inc. will host a conference call for analysts and investors on Tuesday, February 5, 2008 at 4:15 p.m. Eastern time to discuss Husky's annual and fourth 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.



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

A recording of the call will be available at approximately 6:30 p.m.
(Eastern time)
- Dial 1-800-319-6413 (dial reservation # 2658)

The Postview will be available until March 4, 2008.

 




FOR FURTHER INFORMATION PLEASE CONTACT:

Husky Energy Inc.
Tanis Thacker
Manager, Investor Relations
(403) 298-6747

or

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