NEWS RELEASE TRANSMITTED BY Marketwire



FOR: HUSKY ENERGY INC.

TSX SYMBOL:
 HSE

Husky Energy Announces 2006 Third Quarter Results

Oct 19, 2006 - 11:59 ET

CALGARY--(CCNMatthews - Oct. 19) - Husky Energy Inc. reported net earnings of $682 million or $1.61 per share (diluted) in the third quarter of 2006, up 23 percent from $556 million or $1.31 per share (diluted) in the third quarter of 2005. Cash flow from operations in the third quarter was $1.2 billion or $2.88 per share (diluted), a 30 percent increase compared with $944 million or $2.23 per share (diluted) for the same period in 2005. Sales and operating revenues, net of royalties, were $3.4 billion in the third quarter of 2006, compared with $2.6 billion in the third quarter of 2005.

"Husky achieved solid financial and operational results for the third quarter," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "The results demonstrate Husky's ability to effectively execute our strategy while maintaining an emphasis on financial discipline and integration, building a quality asset base for future growth."

Production in the third quarter of 2006 was 364,700 barrels of oil equivalent per day, up 20 percent compared with 303,200 barrels of oil equivalent per day in the third quarter of 2005. Total crude oil and natural gas liquids production was 253,200 barrels per day, compared with 190,000 barrels per day in the third quarter of 2005. Natural gas production was 669.1 million cubic feet per day, compared with 679.2 million cubic feet per day in the third quarter of 2005.

In Western Canada, Husky has successfully implemented an enhanced oil recovery project to extend the production life of the Taber South Mannville B Pool. The $70 million project, which is the first of its kind in Canada, has been awarded with funding support up to $10 million from the Alberta Government's Innovative Energy Technologies Program.

The Tucker Oil Sands Project, located 30 kilometres northwest of Cold Lake, Alberta, was completed on-schedule and under its $500 million budget. First steam was achieved on August 20, 2006 with first oil anticipated in November 2006. During the 35-year life of the project, Husky expects peak production of more than 30,000 barrels per day.

The Sunrise Oil Sands Project continues with front-end engineering design work targeted to be complete by the third quarter of 2007. The Company continues to evaluate alternatives for the downstream portion of the project.

Development planning continues for the Saleski and Caribou Oil Sands Projects. At Saleski, appropriate bitumen recovery processes are being evaluated.

During the third quarter, Husky successfully acquired 46,080 acres of oil sands leases through Alberta land auctions, which added to our holdings in the Saleski area. The acquired leases are estimated to contain 3.3 billion barrels of original bitumen in place within the Grosmont and Nisku carbonates. Husky's holdings at Saleski now total 239,200 acres with original bitumen in place estimated at 24.1 billion barrels.

At the White Rose oil field, gross production in the third quarter averaged 104,700 barrels per day, with 75,900 barrels per day net to Husky. A sixth production well, which is scheduled to come on-stream at the end of 2006, is expected to increase reservoir production capacity to 125,000 barrels of oil per day. Throughput tests were conducted on the White Rose FPSO and plans are being put in place to debottleneck the facility to around 140,000 barrels of oil per day during the scheduled turnaround next summer.

The Terra Nova FPSO returned to the oil field in late September after undergoing repairs and modifications to improve operational efficiency. Hook-up and start-up will proceed during October and oil production is expected to resume at the end of the month.

In the Jeanne d'Arc Basin, approximately 900 square kilometres of 3-D seismic was completed during the third quarter. This program was shot in the vicinity of the White Rose and Terra Nova oil fields to evaluate future exploration opportunities.

Internationally, Husky signed three petroleum contracts with CNOOC (China National Offshore Oil Corporation) for exploration blocks in the South China Sea. The three exploration blocks cover approximately 16,871 square kilometres. Blocks 35/18 and 50/14 are located in the Ying Ge Hai Basin, west of Hainan Island and cover a combined 7,606 square kilometres.

Block 29/06, located in the Pearl Mouth Basin, is adjacent to Block 29/26, which contains the Liwan 3-1-1 discovery. This discovery contains an estimated resource of four to six trillion cubic feet of natural gas. In the third quarter, Husky successfully sidetracked and cored the Liwan 3-1-1 well confirming the pay zones encountered in the original well. Husky also completed a 400 square kilometre 3-D seismic program over the Liwan discovery in September. Further drilling is planned to delineate the discovery.

Regarding midstream and refined products, Husky announced expansion of its mainline crude oil pipeline between Lloydminster and its terminal at Hardisty, Alberta. The expansion will accommodate increased production from the Tucker Oil Sands Project, and shipments from third parties.

Construction at the Lloydminster Ethanol Plant adjacent to the Upgrader was completed. Husky's facility is the largest plant of its kind in Western Canada and will produce annually 130 million litres of ethanol and 134,000 tonnes of Distillers Dried Grain with Solubles, a high protein feed supplement. Construction of a second ethanol plant at Minnedosa, Manitoba is approximately 37 percent complete and should become operational in mid-2007.

At the Prince George Refinery, production throughput increased from 9,600 barrels per day in the third quarter of 2005 to 11,600 barrels per day in the same period of 2006. This increase marks the successful start-up of the low sulphur diesel facilities and completion of the expansion project.

Standard and Poor's Rating Services raised the Company's long-term corporate credit and senior unsecured debt ratings to BBB+ with a stable outlook. Standard and Poor's based its decision on Husky's successful execution and completion of the White Rose project and the Company's very good internal growth prospects, competitive full cycle cost profile and consistently moderate financial risk profile.

The Company has continued to improve its financial strength and flexibility. Debt to capital employed was reduced to 15.6 percent at September 30, 2006 compared with 20.1 percent at December 31, 2005. Debt to cash flow from operations decreased to 0.4 times at September 30, 2006 compared with 0.5 times at December 31, 2005.

Returns on equity and average capital employed have strengthened. Return on equity and return on average capital employed reached 34.2 percent and 28.7 percent respectively for the period ended September 30, 2006.

Husky's net earnings for the first nine months of 2006 were $2.2 billion or $5.15 per share (diluted), compared with $1.3 billion or $3.15 per share (diluted) for the same period in 2005. Cash flow from operations for the first nine months of 2006 was $3.3 billion or $7.76 per share (diluted), compared with $2.6 billion or $6.11 per share (diluted) for the same period in 2005.

Production in the first nine months of 2006 was 354,100 barrels of oil equivalent per day, compared with 310,500 barrels of oil equivalent per day in the same period in 2005. Total crude oil and natural gas liquids production was 241,500 barrels per day, compared with 196,900 barrels per day during the first nine months of 2005. Natural gas production was 675.7 million cubic feet per day, compared with 681.6 million cubic feet per day in the first nine months of 2005.


MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") October 19, 2006


This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. Readers are encouraged to refer to Husky's MD&A and Consolidated Financial Statements and 2005 Annual Information Form filed in 2006 with Canadian regulatory agencies and Form 40-F filed with the Securities and Exchange Commission ("SEC"), the U.S. regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and at www.huskyenergy.ca.

Forward-looking Statements

This MD&A contains forward-looking statements. These statements are based on estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. The reader is advised to refer to Section 14.0 "Forward-looking Statements or Information" for additional information.

Use of Pronouns and Other Terms Denoting Husky

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

Standard Comparisons in this Document

Unless otherwise indicated, the discussions in this MD&A with respect to results for the three months ended September 30, 2006 are compared with results for the three months ended September 30, 2005 and results for the nine months ended September 30, 2006 are compared with results for the nine months ended September 30, 2005. Discussions with respect to Husky's financial position as at September 30, 2006 are compared with its financial position at December 31, 2005.

Additional Reader Guidance


- The Consolidated Financial Statements and comparative financial

information included in this Interim Report have been prepared in

accordance with Canadian generally accepted accounting principles

("GAAP").

- All dollar amounts are in millions of Canadian dollars, unless

otherwise indicated.

- Unless otherwise indicated, all production volumes quoted are gross,

which represent the Company's working interest share before royalties.

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


1.0 SUMMARY OF QUARTERLY RESULTS

Husky's net earnings for the third quarter of 2006 were $682 million, up $126 million compared with the third quarter of 2005.

Higher earnings in the third quarter of 2006 were primarily due to higher crude oil production from the White Rose oil field, higher crude oil prices and higher light refined product margins. These positive factors were partially offset by lower natural gas prices and sales volume, suspension of production at Terra Nova and production declines at Wenchang.



Financial Summary

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

Financial Summary

(millions of dollars, except Sept. 30 June 30 March 31 Dec. 31

per share amounts and ratios) 2006 2006 2006 2005

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

Sales and operating revenues,

net of royalties $ 3,436 $ 3,040 $ 3,104 $ 3,207

Segmented earnings

Upstream $ 608 $ 822 $ 412 $ 533

Midstream 87 140 150 135

Refined Products 28 52 16 17

Corporate and eliminations (41) (36) (54) (16)

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

Net earnings $ 682 $ 978 $ 524 $ 669

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

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

Per share - Basic $ 1.61 $ 2.31 $ 1.24 $ 1.58

- Diluted 1.61 2.31 1.24 1.58

Cash flow from operations 1,224 1,103 967 1,197

Per share - Basic 2.88 2.60 2.28 2.82

- Diluted 2.88 2.60 2.28 2.82

Dividends per common share 0.50 0.25 0.25 0.25

Special dividend per common share - - - 1.00

Total assets 17,389 16,405 15,859 15,797

Total long-term debt including

current portion 1,722 1,722 1,838 1,886

Return on equity(1) (percent) 34.2 34.8 29.6 29.2

Return on average capital

employed(1) (percent) 28.7 28.2 23.2 22.8

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

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

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

Financial Summary

(millions of dollars, except Sept. 30 June 30 March 31 Dec. 31

per share amounts and ratios) 2005 2005 2005 2004

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

Sales and operating revenues,

net of royalties $ 2,594 $ 2,350 $ 2,094 $ 2,018

Segmented earnings

Upstream $ 445 $ 307 $ 239 $ 112

Midstream 61 130 169 77

Refined Products 27 20 18 (3)

Corporate and eliminations 23 (63) (42) 39

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

Net earnings $ 556 $ 394 $ 384 $ 225

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

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

Per share - Basic $ 1.31 $ 0.93 $ 0.91 $ 0.53

- Diluted 1.31 0.93 0.91 0.53

Cash flow from operations 944 828 816 469

Per share - Basic 2.23 1.95 1.93 1.11

- Diluted 2.23 1.95 1.93 1.11

Dividends per common share 0.14 0.14 0.12 0.12

Special dividend per common share - - - 0.54

Total assets 14,712 14,058 13,690 13,240

Total long-term debt including

current portion 1,896 2,192 2,290 2,103

Return on equity(1) (percent) 22.9 20.2 18.3 17.0

Return on average capital

employed(1) (percent) 17.9 15.3 13.9 13.0

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

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

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

 


Western Canada crude oil production rose marginally in the third quarter of 2006 compared with the second quarter of 2006 as a result of higher production of heavy crude oil. Natural gas sales volume decreased marginally from the second quarter of 2006 to the third quarter of 2006.

In the third quarter of 2006, 128 gross (95 net) exploration wells were drilled in the Western Canada Sedimentary Basin ("WCSB") resulting in 41 gross (40 net) oil wells and 82 gross (50 net) gas wells.

At White Rose the fifth production well came on-stream on June 25 raising production capacity to 110-115 mbbls/day (80-83 mbbls/day Husky's share).

At Terra Nova, production operations were suspended on May 7, 2006 and the FPSO was sent to dry dock in the Netherlands for repairs, maintenance and modifications. The FPSO returned to the field on September 25 and was connected to the spider buoy on October 1. Terra Nova is expected to commence production at the end of the month.

Wenchang oil field production declined marginally in the third quarter of 2006 compared with the second quarter of 2006 reflecting natural reservoir decline combined with downtime for weather and liquefied petroleum gas facilities installation.



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

Daily Gross Production Three months ended

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

2006 2006 2006 2005 2005

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

Crude oil and NGL

(mbbls/day)

Western Canada

Light crude oil & NGL 30.2 29.8 31.3 30.1 31.8

Medium crude oil 28.1 28.5 29.4 31.0 30.3

Heavy crude oil 107.9 105.6 109.5 109.5 103.3

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

166.2 163.9 170.2 170.6 165.4

East Coast Canada

White Rose -

light crude oil 75.9 53.0 46.4 19.0 -

Terra Nova -

light crude oil - 2.8 9.3 12.2 10.2

China

Wenchang -

light crude oil 11.1 12.1 13.5 14.1 14.4

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

253.2 231.8 239.4 215.9 190.0

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

Natural gas (mmcf/day) 669.1 672.8 685.4 675.3 679.2

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

Total (mboe/day) 364.7 344.0 353.6 328.5 303.2

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

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

 


Production

During the third quarter of 2006 White Rose was further developed and Husky's share averaged 75.9 mbbls/day. This increase in production was partially offset by the Terra Nova oil field, shut-in for repairs and unscheduled maintenance and modifications.

2.0 STRATEGIC PLANS AND CAPABILITIES

The following projects are at various stages of development and, upon completion, are expected to provide for sustained growth to the Company.

Upstream


- East Coast Exploration and Development

- Oil Sands Development

- Mackenzie River Valley Exploration

- China and Indonesia Exploration and Development

Midstream

- Upgrader Expansion

Refined Products

- Refinery Modifications

- Ethanol Plant Construction



2.1 UPSTREAM

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

Gross Production Nine months Nine months

ended Full Year ended Year ended

Sept. 30 Forecast Sept. 30 Dec. 31

2006 2006 2005 2005

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

Crude oil & NGL (mbbls/day)

Light crude oil & NGL 105.1 103 - 116 61.0 64.6

Medium crude oil 28.7 29 - 32 31.1 31.1

Heavy crude oil 107.7 115 - 120 104.8 106.0

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

241.5 247 - 268 196.9 201.7

Natural gas (mmcf/day) 675.7 680 - 730 681.6 680.0

Total barrels of

oil equivalent (mboe/day) 354.1 360 - 390 310.5 315.0

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

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

 


Our assets in the WCSB currently provide the majority of the funding required to finance our strategic plans including exploitation activities, which involve increased drilling of infill and step-out wells, and the installation of various types of enhanced recovery techniques, including thermal recovery of heavy oil and emerging technologies such as alkaline surfactant polymer floods.

Exploration for significant resources in the WCSB is concentrated in specific areas of the foothills, deep basin and northern plains of Alberta and British Columbia. These natural gas prone areas involve assiduous exploration processes that target multi-zone potential, natural gas reserves from unconventional sources and optimization of existing infrastructure through extension of established producing areas.

White Rose Oil Field

White Rose now has five producing wells with a productive capacity of 110-115 mbbls/day (80-83 mbbls/day Husky's share). In the third quarter we performed a detailed technical and operational review of the field, including a performance test of the production processing facilities on board the SeaRose FPSO. This test demonstrated that the processing facilities are able to support an annual average of 125 mbbls/day (90.6 mbbls/day Husky's share). Reservoir capacity is expected to be higher than 125 mbbls/day with the completion of a sixth production well by the end of 2006.

East Coast Canada Exploration and Delineation

In the third quarter of 2006 we drilled the West Bonne Bay F-12, a delineation well in the Significant Discovery Licence 1040, which is adjacent to the Terra Nova field. Preliminary results indicate hydrocarbons in the Upper Hibernia Reservoir. Well results are being evaluated.

The 3-D seismic program covering a total of 896 square kilometres was shot on Exploration Licence 1067, which is northwest of White Rose, and near Fortune, which is located on Significant Discovery Licence 1011, southwest of White Rose. Planning is well underway for our 2007 exploration and delineation drilling program which currently includes three locations in the Jeanne d'Arc Basin.

Tucker Oil Sands Project

During the third quarter of 2006 construction was completed at the Tucker steam-assisted gravity drainage in-situ oil sands project and the steam generation facilities were commissioned. Steam injection into two of three pads commenced on August 20, 2006. Steam injection at the remaining pad is expected to commence by the end of October. First bitumen production is expected to be on-schedule in November 2006.

Sunrise Oil Sands Project

The conceptual design for the upstream development at the Sunrise Oil Sands Project progressed well. This aspect of the project includes options for field development, oil treatment and steam generation and is approximately 55 percent complete. The entire front-end engineering design ("FEED") for Sunrise is scheduled to be complete by the third quarter of 2007.

During the third quarter, we drilled five source water evaluation wells and we plan to drill 10 more this winter. We are currently completing seismic studies and have determined 29 stratigraphic well locations for the winter drilling season. Collaboration with various industry participants continued on regional infrastructure issues, including an access highway and airport.

Caribou and Saleski

During the third quarter of 2006 we participated in two land sales in the Saleski area and acquired leases totalling 46,080 acres. These leases are currently estimated to hold approximately 3.3 billion barrels of bitumen in place within the Grosmont and Nisku carbonates. We now hold leases totalling 239,200 acres in the Saleski area, which are estimated to contain 24.1 billion barrels of bitumen in place.

In addition, conceptual development planning continued with water source and disposal well studies for both Saleski and Caribou and determination of an appropriate bitumen recovery process for Saleski. At Caribou we completed selection of 44 stratigraphic well locations to be drilled during the winter drilling season.

Northwest Territories Exploration

A seismic program was shot during the third quarter that included our newly acquired Exploration Licence 441, which is contiguous with the eastern boundary of our Exploration Licence 397 containing the Stewart D-57 natural gas discovery. Based on the timing of this seismic program and subsequent analytical work we, with our partners, have decided to defer further exploration drilling until the winter of 2007/2008. This will allow for full incorporation of new seismic data into the prospect mapping that is currently underway.

China Exploration

During the third quarter of 2006 we acquired three exploration blocks offshore China that in aggregate total 16,871 square kilometres. Block 29/06 is 9,265 square kilometres and located in the Pearl River Mouth Basin adjacent to Block 29/26, the location of the Liwan natural gas discovery. Block 35/18 is 4,469 square kilometres and Block 50/14 is 3,137 square kilometres; both are located in the Ying Ge Hai Basin west of Hainan Island. Under the terms of the agreement we will pay 100 percent of the costs to drill two wells on Block 29/06 and one well on each of the other two blocks. The China National Offshore Oil Corporation has the option to participate in up to 51 percent of any future development.

At the Liwan natural gas discovery a side track well confirmed the pay zones in the original well. We also completed shooting 400 square kilometres of 3-D seismic over the Liwan discovery and it is currently being analyzed in preparation for delineation drilling. We are currently seeking tenders to drill an exploration well on Block 04/35 in the East China Sea and expect a spud date in the first half of 2007.

Indonesia Natural Gas Development

At Madura, negotiations for a natural gas sales agreement are continuing. Development of the Madura natural gas field is contingent on receiving government approval. In September Husky signed the Production Sharing Contract for the East Bawean II Block.

2.2 MIDSTREAM

In August 2006 we announced the expansion of the Lloydminster to Hardisty section of our pipeline. The expansion, which will run from Wainwright and Battle River, Alberta to Lloydminster will involve the installation of 24 inch (610 mm) pipelines and associated facilities and will be done in two phases. Completion of both phases is expected by the fourth quarter of 2007.

Lloydminster Upgrader

The FEED for the expansion of the Lloydminster Upgrader progressed to approximately 16 percent of completion. Completion of the FEED is scheduled for the third quarter of 2007. During the quarter we commenced the environmental phase of the regulatory approval process with the Government of Saskatchewan. The expansion envisions increasing throughput capacity from 80 mbbls/day to 150 mbbls/day.

2.3 REFINED PRODUCTS

Lloydminster and Minnedosa Ethanol Plants

To meet the increasing demand for ethanol blended gasoline, we are progressing with two motor fuel grade ethanol plants. One plant is located adjacent to our Upgrader at Lloydminster, Saskatchewan and the other at Minnedosa, Manitoba, the site of our existing ethanol plant. Each plant will have throughput capacity of 130 million litres of ethanol per year. During the third quarter of 2006 the Lloydminster Ethanol Plant was completed and we are currently in start-up mode. At Minnedosa, Manitoba construction of that ethanol plant is approximately 37 percent complete and is scheduled for completion in the third quarter of 2007.

3.0 BUSINESS ENVIRONMENT

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



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

Average Benchmark Three months ended

Prices and U.S. Sept. 30 June 30 March 31 Dec. 31 Sept. 30

Exchange Rate 2006 2006 2006 2005 2005

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

WTI crude oil(1)

(U.S. $/bbl) 70.48 70.70 63.48 60.02 63.10

Brent crude oil(2)

(U.S. $/bbl) 69.49 69.62 61.75 56.90 61.54

Canadian par light

crude 0.3% sulphur

($/bbl) 79.65 78.97 69.40 71.65 77.04

Lloyd heavy crude oil

@ Lloydminster

($/bbl) 49.61 48.65 26.25 29.60 44.13

NYMEX natural gas(1)

(U.S. $/mmbtu) 6.58 6.79 8.98 12.97 8.49

NIT natural gas ($/GJ) 5.72 5.95 8.79 11.08 7.75

WTI/Lloyd crude blend

differential

(U.S. $/bbl) 19.24 17.99 29.20 24.24 18.90

U.S./Canadian dollar

exchange rate (U.S. $) 0.892 0.891 0.866 0.852 0.833

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

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

(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.

 


3.1 COMMODITY PRICE RISK

Our earnings depend largely on the profitability of our upstream business segment which is significantly affected by fluctuations in oil and gas prices. Commodity prices have been, and are expected to continue to be, volatile due to a number of factors beyond our control. The effect of any single risk is not determinable with certainty as these are interdependent and our future course of action depends upon our assessment of all information available at any given time.

Crude Oil

WTI and Husky Average Crude Oil Prices

The price of West Texas Intermediate crude oil rose through the first six months of 2006, and declined marginally during the third quarter. Our light and medium crude oil prices followed suit while heavy crude oil prices rose marginally, narrowing the light/heavy crude price differential.

WTI, the benchmark crude price, has escalated throughout the period reported with some fluctuations, closely followed by Husky's light crude prices.

The prices received for our crude oil and NGL are related to the price of crude oil in world markets. Prices for heavy crude oil and other lesser quality crudes trade at a discount or differential to light crude oil due to the additional processing costs.

Concerns about global crude oil supply seem to have been abated, in part due to no hurricane damage to producing facilities in the Gulf of Mexico this year, Iran's participation in continued negotiation in respect of the uranium enrichment issue, the absence of Nigeria's past production disruptions and the stabilization of Iraq production at levels not achieved since fall of 2004. All of these and other issues that could affect the global supply/demand balance are subject to change at any time. As a result, there can be no certainty concerning the foreseeable future of crude oil prices.

Natural Gas

NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices

Both U.S. and Canadian benchmark natural gas prices decreased in 2006. Husky's natural gas prices, which are dominated by floating prices, followed suit.

The price of natural gas in North America is affected by regional supply and demand factors, particularly those affecting the United States such as weather conditions, pipeline delivery capacity, production disruptions, the availability of alternative sources of less costly energy supply, inventory levels and general industry activity levels. Periodic imbalances between supply and demand for natural gas are common and result in volatile pricing.

Natural gas prices on NYMEX have declined to levels not seen since September 2004 with near-month contracts trading around the U.S. $5.00/mmbtu mark. Natural gas in storage in the United States at the end of September was approximately 12 percent above five year averages.

Other Business Environment Risks

Please refer to our 2005 MD&A for a discussion about other business environment risks.

3.2 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 third quarter of 2006. 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

2006

Third

Quarter

Average Increase

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

Upstream and Midstream

WTI benchmark crude oil price 70.48 U.S. $1.00/bbl

NYMEX benchmark natural gas price(1) 6.58 U.S. $0.20/mmbtu

WTI/Lloyd crude blend differential(2) 19.24 U.S. $1.00/bbl

Exchange rate (U.S. $ per Cdn $)(3) 0.89 U.S. $0.01

Refined Products

Light oil margins 0.05 Cdn $0.005/litre

Asphalt margins 4.97 Cdn $1.00/bbl

Consolidated

Period end translation of U.S. $ debt

(U.S. $ per Cdn $) 0.90(4) U.S. $0.01

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

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

Effect on Pre-tax Effect on

Cash Flow Net Earnings

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

($ millions) ($/ ($ millions) ($/

share) share)

(5) (5)

Upstream and Midstream

WTI benchmark crude oil price 92 0.22 61 0.14

NYMEX benchmark natural gas price(1) 38 0.09 25 0.06

WTI/Lloyd crude blend differential(2) (28) (0.06) (18) (0.04)

Exchange rate (U.S. $ per Cdn $)(3) (75) (0.18) (49) (0.11)

Refined Products

Light oil margins 17 0.04 11 0.03

Asphalt margins 11 0.03 7 0.02

Consolidated

Period end translation of U.S. $ debt

(U.S. $ per Cdn $) 8 0.02

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

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

(1) Includes decrease in earnings related to natural gas consumption.

(2) Includes impact of upstream and upgrading operations only.

(3) Assumes no foreign exchange gains or losses on U.S. dollar

denominated long-term debt and other monetary items.

(4) U.S./Canadian dollar exchange rate at September 30, 2006.

(5) Based on September 30, 2006 common shares outstanding of

424.3 million.

 


4.0 RESULTS OF OPERATIONS

Quarterly Segmented Earnings

Husky's profitability is largely dependant on Upstream operations, partially supported by upgrading results during times when light/heavy crude oil differentials are wider.

4.1 UPSTREAM

Third Quarter

Upstream earnings were $163 million higher in the third quarter of 2006 than in the third quarter of 2005 as a result of the following factors:


- higher sales volume of light crude oil from White Rose and heavy

crude oil from the Lloydminster area;

- higher light, medium and heavy crude oil prices; and

- lower natural gas royalties.

Partially offset by:

- lower natural gas prices;

- lower sales volume of light crude oil from Terra Nova and lower sales

volume of medium crude oil and natural gas;

- higher unit operating costs;

- higher unit depletion, depreciation and amortization; and

- higher income taxes.

Nine Months

The factors that affected results for the third quarter also affected variances in results for the nine months ended September 30, 2006.



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

Upstream Earnings Summary Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars) 2006 2005 2006 2005

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

Gross revenues $ 1,816 $ 1,422 $ 4,967 $ 3,616

Royalties 216 246 629 576

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

Net revenues 1,600 1,176 4,338 3,040

Operating and

administration expenses 329 262 948 751

Depletion, depreciation

and amortization 382 280 1,087 831

Income taxes 281 189 461 467

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

Earnings $ 608 $ 445 $ 1,842 $ 991

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

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

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

Net Revenue Variance Analysis

Crude oil Natural

(millions of dollars) & NGL gas Other Total

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

Three months ended

September 30, 2005 $ 771 $ 384 $ 21 $ 1,176

Price changes 118 (129) - (11)

Volume changes 405 (7) - 398

Royalties (8) 39 - 31

Processing and sulphur - - 6 6

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

Three months ended

September 30, 2006 $ 1,286 $ 287 $ 27 $ 1,600

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

Nine months ended

September 30, 2005 $ 1,966 $ 1,016 $ 58 $ 3,040

Price changes 631 (54) - 577

Volume changes 766 (11) - 755

Royalties (92) 39 - (53)

Processing and sulphur - - 19 19

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

Nine months ended

September 30, 2006 $ 3,271 $ 990 $ 77 $ 4,338

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

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

 


Unit Operating Costs

Unit operating costs were three percent higher in the third quarter of 2006 compared with the same period in 2005 primarily due to higher costs for labour, field services, trucking, shallow natural gas compression, higher natural gas well count and production declines. Unit operating costs were also affected by the Terra Nova turnaround and generally fixed costs associated with production declines. Unit operating costs were partially offset by lower turnaround activity in our Western Canada operations and a higher proportion of lower operating cost production from White Rose. The high level of industry activity has created increased demand and consequently higher prices for oil field materials and services.

Netback and Unit Operating Cost

Higher netbacks due to higher crude oil prices were marginally affected by increases in operating costs.

Unit Depletion, Depreciation and Amortization

Unit depletion, depreciation and amortization expense increased 13 percent in the third quarter of 2006 compared with the same period in 2005. The increase was primarily due to net growth of the capital base in 2006 as a result of increased requirements for production maintenance capital in the WCSB and the start-up of the White Rose oil field, which has a higher ratio of capital to reserves. Also contributing to higher unit depletion are purchases of reserves-in-place, which on a unit cost basis are above the average depletion rate. In addition, higher energy costs, as with operating costs, increased the cost of materials and services embedded in our capital costs.



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

Average Sales Prices Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

Crude Oil ($/bbl)

Light crude oil & NGL $ 74.05 $ 67.21 $ 71.74 $ 60.85

Medium crude oil 57.35 53.41 51.28 43.34

Heavy crude oil 49.62 44.17 41.45 31.46

Total average 61.79 52.54 55.81 42.43

Natural Gas ($/mcf)

Average 5.69 7.86 6.57 6.90

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

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

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

Effective Royalty Rates Three months Nine months

ended Sept. 30 ended Sept. 30

Percentage of upstream

sales revenues 2006 2005 2006 2005

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

Crude oil & NGL 11% 16% 11% 14%

Natural gas 18% 21% 18% 20%

Total 12% 17% 13% 16%

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

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

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

Upstream Revenue Mix Three months Nine months

ended Sept. 30 ended Sept. 30

Percentage of upstream sales

revenues, after royalties 2006 2005 2006 2005

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

Crude oil & NGL

Light crude oil & NGL 47% 26% 44% 29%

Medium crude oil 7% 10% 8% 10%

Heavy crude oil 27% 30% 24% 26%

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

81% 66% 76% 65%

Natural gas 19% 34% 24% 35%

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

100% 100% 100% 100%

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

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

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

Operating Netbacks

WCSB East Coast

Three months ended Sept. 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 62.61 $ 65.25 $ 75.78 $ 69.62

Royalties 9.43 10.02 0.77 12.64

Operating costs 7.40 6.62 6.03 5.61

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

45.78 48.61 68.98 51.37

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

Medium Crude Oil (per boe)(1)

Sales Price 56.35 53.13 - -

Royalties 10.02 9.69 - -

Operating costs 12.99 11.44 - -

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

33.34 32.00 - -

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

Heavy Crude Oil (per boe)(1)

Sales Price 49.41 44.19 - -

Royalties 6.71 6.25 - -

Operating costs 10.69 9.88 - -

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

32.01 28.06 - -

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

Total Crude Oil (per boe)(1)

Sales Price 52.94 49.85 75.78 69.62

Royalties 7.77 7.62 0.77 12.64

Operating costs 10.52 9.57 6.03 5.61

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

34.65 32.66 68.98 51.37

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

Natural Gas (per mcfge)(2)

Sales Price 5.99 7.90 - -

Royalties 1.21 1.78 - -

Operating costs 1.23 1.17 - -

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

3.55 4.95 - -

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

Equivalent Unit (per boe)(1)

Sales Price 46.24 48.86 75.78 69.62

Royalties 7.56 8.82 0.77 12.64

Operating costs 9.29 8.56 6.03 5.61

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

$ 29.39 $ 31.48 $ 68.98 $ 51.37

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

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

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

International Total

Three months ended Sept. 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 77.07 $ 67.98 $ 72.58 $ 66.80

Royalties 16.80 6.53 4.52 9.56

Operating costs 4.24 2.56 6.20 5.46

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

56.03 58.89 61.86 51.78

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

Medium Crude Oil (per boe)(1)

Sales Price - - 56.35 53.13

Royalties - - 10.02 9.69

Operating costs - - 12.99 11.44

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

- - 33.34 32.00

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

Heavy Crude Oil (per boe)(1)

Sales Price - - 49.41 44.19

Royalties - - 6.71 6.25

Operating costs - - 10.69 9.88

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

- - 32.01 28.06

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

Total Crude Oil (per boe)(1)

Sales Price 77.07 67.98 60.79 52.28

Royalties 16.80 6.53 6.09 7.79

Operating costs 4.24 2.56 8.91 8.84

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

56.03 58.89 45.79 35.65

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

Natural Gas (per mcfge)(2)

Sales Price - - 5.99 7.90

Royalties - - 1.21 1.78

Operating costs - - 1.23 1.17

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

- - 3.55 4.95

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

Equivalent Unit (per boe)(1)

Sales Price 77.07 67.98 53.35 50.49

Royalties 16.80 6.53 6.44 8.83

Operating costs 4.24 2.56 8.45 8.18

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

$ 56.03 $ 58.89 $ 38.46 $ 33.48

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

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

(1) Includes associated co-products converted to boe.

(2) Includes associated co-products converted to mcfge.

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

WCSB East Coast

Nine months ended Sept. 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 61.86 $ 57.85 $ 74.22 $ 62.23

Royalties 7.37 7.54 1.94 5.61

Operating costs 10.59 9.16 6.10 4.16

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

43.90 41.15 66.18 52.46

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

Medium Crude Oil (per boe)(1)

Sales Price 50.65 43.32 - -

Royalties 9.01 7.68 - -

Operating costs 12.34 10.68 - -

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

29.30 24.96 - -

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

Heavy Crude Oil (per boe)(1)

Sales Price 41.42 31.57 - -

Royalties 5.39 3.83 - -

Operating costs 10.74 9.53 - -

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

25.29 18.21 - -

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

Total Crude Oil (per boe)(1)

Sales Price 46.57 38.60 74.22 62.23

Royalties 6.37 5.25 1.94 5.61

Operating costs 11.00 9.68 6.10 4.16

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

29.20 23.67 66.18 52.46

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

Natural Gas (per mcfge)(2)

Sales Price 6.76 6.97 - -

Royalties 1.43 1.56 - -

Operating costs 1.10 1.04 - -

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

4.23 4.37 - -

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

Equivalent Unit (per boe)(1)

Sales Price 44.18 39.86 74.22 62.23

Royalties 7.25 6.88 1.94 5.61

Operating costs 9.25 8.31 6.10 4.16

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

$ 27.68 $ 24.67 $ 66.18 $ 52.46

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

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

International Total

Nine months ended Sept. 30 2006 2005 2006 2005

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

Light Crude Oil (per boe)(1)

Sales Price $ 76.05 $ 64.04 $ 71.01 $ 60.57

Royalties 12.68 6.00 4.73 6.68

Operating costs 3.46 2.43 7.03 6.20

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

59.91 55.61 59.25 47.69

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

Medium Crude Oil (per boe)(1)

Sales Price - - 50.65 43.32

Royalties - - 9.01 7.68

Operating costs - - 12.34 10.68

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

- - 29.30 24.96

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

Heavy Crude Oil (per boe)(1)

Sales Price - - 41.42 31.57

Royalties - - 5.39 3.83

Operating costs - - 10.74 9.53

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

- - 25.29 18.21

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

Total Crude Oil (per boe)(1)

Sales Price 76.05 64.04 55.19 42.24

Royalties 12.68 6.00 5.55 5.33

Operating costs 3.46 2.43 9.35 8.74

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

59.91 55.61 40.29 28.17

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

Natural Gas (per mcfge)(2)

Sales Price - - 6.76 6.97

Royalties - - 1.43 1.56

Operating costs - - 1.10 1.04

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

- - 4.23 4.37

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

Equivalent Unit (per boe)(1)

Sales Price 76.05 64.04 50.59 42.07

Royalties 12.68 6.00 6.50 6.78

Operating costs 3.46 2.43 8.50 7.84

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

$ 59.91 $ 55.61 $ 35.59 $ 27.45

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

(1) Includes associated co-products converted to boe.

(2) Includes associated co-products converted to mcfge.

Upstream Capital Expenditures

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

Capital Expenditures Summary(1) Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars) 2006 2005 2006 2005

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

Exploration

Western Canada $ 140 $ 189 $ 460 $ 503

East Coast Canada

and Frontier 16 28 41 46

International 32 16 69 39

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

188 233 570 588

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

Development

Western Canada 325 262 1,082 856

East Coast Canada 88 202 251 448

International 11 4 20 7

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

424 468 1,353 1,311

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

$ 612 $ 701 $ 1,923 $ 1,899

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

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

(1) Excludes capitalized costs related to asset retirement obligations

incurred during the period.

 


Upstream capital expenditures totaled $1,923 million, 83 percent of total consolidated capital expenditures during the first nine months of 2006 compared with $1,899 million or 89 percent of the total, during the first nine months of 2005.



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

Western Canada Wells Three months Nine months

Drilled(1)(2) ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

Gross Net Gross Net Gross Net Gross Net

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

Exploration Oil 41 40 28 28 71 70 63 60

Gas 82 50 107 43 278 150 239 136

Dry 5 5 7 7 24 22 26 26

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

128 95 142 78 373 242 328 222

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

Development Oil 184 163 154 147 380 334 285 266

Gas 128 115 164 136 382 331 442 401

Dry 9 6 10 8 20 17 25 23

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

321 284 328 291 782 682 752 690

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

Total 449 379 470 369 1,155 924 1,080 912

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

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

(1) Excludes stratigraphic test wells.

(2) Includes non-operated wells.

 


4.2 MIDSTREAM

Third Quarter

Upgrading earnings in the third quarter of 2006 were $27 million greater than the third quarter of 2005 due to higher sales volume of synthetic crude oil partially offset by higher income taxes.

Nine Months

Upgrading earnings in the nine months of 2006 were $5 million less than 2005 due to reduced differentials and increased operating costs offset by improved sales volume of synthetic crude and lower income taxes.



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

Upgrading Earnings Summary Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars,

except where indicated) 2006 2005 2006 2005

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

Gross margin $ 135 $ 92 $ 479 $ 494

Operating costs 50 48 169 151

Other recoveries (1) (1) (4) (4)

Depreciation and amortization 6 6 18 15

Income taxes 26 12 70 101

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

Earnings $ 54 $ 27 $ 226 $ 231

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

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

Selected operating data:

Upgrader throughput(1)

(mbbls/day) 73.1 48.3 71.0 63.8

Synthetic crude oil sales

(mbbls/day) 65.7 43.9 62.0 55.9

Upgrading differential

($/bbl) $ 23.75 $ 23.53 $ 27.04 $ 29.73

Unit margin ($/bbl) $ 22.38 $ 23.01 $ 28.31 $ 32.41

Unit operating cost(2)

($/bbl) $ 7.62 $ 11.04 $ 8.73 $ 8.71

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

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

(1) Throughput includes diluent returned to the field.

(2) Based on throughput.

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

Upgrading Earnings Variance Analysis

(millions of dollars)

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

Three months ended September 30, 2005 $ 27

Volume 46

Margin (3)

Operating costs - energy related (1)

Operating costs - non-energy related (1)

Depreciation and amortization -

Income taxes (14)

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

Three months ended September 30, 2006 $ 54

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

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

Nine months ended September 30, 2005 $ 231

Volume 54

Margin (69)

Operating costs - energy related (5)

Operating costs - non-energy related (13)

Depreciation and amortization (3)

Income taxes 31

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

Nine months ended September 30, 2006 $ 226

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

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

 


Third Quarter

Infrastructure and marketing earnings in the third quarter of 2006 decreased marginally compared with 2005 primarily due to inventory adjustments on blended heavy crude oil partially offset by higher heavy crude oil pipeline throughput and margins.

Nine Months

Infrastructure and marketing earnings in the nine months of 2006 increased by $22 million compared with 2005 primarily due to higher crude oil pipeline throughput and margins, higher natural gas marketing income and lower income taxes partially offset by lower income from blended heavy crude oil marketing.



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

Infrastructure and Marketing

Earnings Summary Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars,

except where indicated) 2006 2005 2006 2005

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

Gross margin - pipeline $ 26 $ 21 $ 80 $ 68

- other

infrastructure

and marketing 32 38 152 154

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

58 59 232 222

Other expenses 3 3 8 8

Depreciation and amortization 6 5 17 16

Income taxes 16 17 56 69

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

Earnings $ 33 $ 34 $ 151 $ 129

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

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

Selected operating data:

Aggregate pipeline

throughput (mbbls/day) 457 418 479 472

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

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

 


Midstream Capital Expenditures

Midstream capital expenditures totaled $160 million in the first nine months of 2006; $119 million at the Lloydminster Upgrader, primarily for debottleneck and reliability projects and $41 million on pipelines and infrastructure.

4.3 REFINED PRODUCTS

Third Quarter

Refined Products earnings in the third quarter of 2006 increased by $1 million compared with the third quarter of 2005 due to:


- higher marketing margins for gasoline and distillates.

Partially offset by:

- lower sales volume of refined products.

Nine Months

Refined Products earnings in the nine months of 2006 increased by $31 million compared with 2005 due primarily to higher marketing margins for gasoline and distillates, reduced operating costs and lower income taxes.



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

Refined Products

Earnings Summary Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars,

except where indicated) 2006 2005 2006 2005

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

Gross margin - fuel sales $ 42 $ 41 $ 121 $ 94

- ancillary

sales 10 10 26 26

- asphalt sales 18 24 71 71

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

70 75 218 191

Operating and other expenses 18 19 53 55

Depreciation and amortization 11 14 34 34

Income taxes 13 15 35 37

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

Earnings $ 28 $ 27 $ 96 $ 65

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

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

Selected operating data:

Number of fuel outlets 504 519

Light oil sales

(million litres/day) 9.1 9.3 8.7 8.8

Light oil retail sales

per outlet

(thousand litres/day) 13.6 13.3 12.8 12.7

Prince George refinery

throughput (mbbls/day)(1) 11.6 9.6 8.2 9.7

Asphalt sales (mbbls/day) 30.0 29.9 24.2 22.5

Lloydminster refinery

throughput (mbbls/day) 27.9 25.9 26.8 24.9

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

(1) Prince George throughput decreased in the second quarter of 2006 as a

result of a plant shutdown for the commissioning of the low sulphur

diesel modifications.

 


Refined Products Capital Expenditures

Refined Products capital expenditures totaled $202 million in the first nine months of 2006; $37 million at the Prince George refinery, $82 million at the Lloydminster ethanol plant and $60 million at the Minnedosa ethanol plant.

4.4 CORPORATE

Third Quarter

Corporate expense increased by $64 million in the third quarter of 2006 compared with the third quarter of 2005 due to:


- gain on translation of U.S. denominated debt in 2005;

- gain on settlement of litigation recognized in 2005; and

- lower capitalized interest due to start-up of the White Rose oil

field.

Partially offset by:

- lower stock-based compensation expense; and

- lower profit elimination on inventory.

Nine Months

The factors that affected results for the third quarter also affected variances in the results for the nine months ended September 30, 2006.



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

Corporate Summary

Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars)

income (expense) 2006 2005 2006 2005

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

Intersegment

eliminations - net $ (2) $ (44) $ (16) $ (53)

Administration

expenses (7) (4) (19) (15)

Stock-based

compensation (18) (79) (103) (177)

Accretion (1) (1) (2) (2)

Other - net (11) 57 (19) 51

Depreciation and

amortization (6) (6) (17) (17)

Interest on debt (28) (36) (98) (108)

Interest capitalized 9 36 30 91

Interest income - - - 1

Foreign exchange

- realized - (1) 19 4

Foreign exchange

- unrealized (5) 64 13 32

Income taxes 28 37 81 111

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

Earnings (loss) $ (41) $ 23 $ (131) $ (82)

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

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

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

Foreign Exchange Rates

Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

U.S./Canadian dollar

exchange rates:

At beginning of

period U.S. $0.897 U.S. $0.816 U.S. $0.858 U.S. $0.831

At end of period U.S. $0.897 U.S. $0.861 U.S. $0.897 U.S. $0.861

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

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

 


Consolidated Income Taxes

During the third quarter of 2006 consolidated income taxes consisted of $210 million of current taxes and $98 million of future taxes compared with current taxes of $78 million and future taxes of $118 million in the same period of 2005.

The increase in current taxes in the third quarter of 2006 compared with the third quarter of 2005 was due to higher taxable income.

In the second quarter of 2006, a recovery of future taxes resulted from recording non-recurring tax benefits of $328 million that arose due to changes in the tax rates for the governments of Canada ($198 million), Alberta ($90 million) and Saskatchewan ($40 million). All of this tax legislation received royal assent and was, therefore, substantively enacted in the second quarter of 2006.

Corporate Capital Expenditures

Corporate capital expenditures totaled $23 million in the first nine months of 2006 primarily for various office and information system upgrades.

5.0 LIQUIDITY AND CAPITAL RESOURCES

During the third quarter cash flow from operating activities financed all of our capital requirements and dividend payment. At September 30, 2006 we had $1.4 billion in unused committed credit facilities.



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

Cash Flow Summary Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars,

except ratios) 2006 2005 2006 2005

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

Cash flow

- operating activities $ 1,461 $ 1,105 $ 3,887 $ 2,605

- financing activities $ (333) $ (290) $ (1,181) $ (543)

- investing activities $ (713) $ (776) $ (2,346) $ (2,027)

Financial Ratios

Debt to capital employed

(percent) 15.6 20.4

Corporate reinvestment

ratio(1)(2) 0.7 0.9

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

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

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

(2) Reinvestment ratio is based on net capital expenditures including

corporate acquisitions.

 


5.1 OPERATING ACTIVITIES

In the third quarter of 2006, cash generated from operating activities amounted to $1.5 billion compared with $1.1 billion in the third quarter of 2005. Higher cash flow from operating activities was primarily due to higher production volumes and a larger decrease in non-cash working capital resulting primarily from an increase in cash income taxes payable.

5.2 FINANCING ACTIVITIES

In the third quarter of 2006, cash used in financing activities amounted to $333 million compared with $290 million in the third quarter of 2005. During the third quarter of 2006, higher dividends and non-cash working capital associated with financing activities primarily resulted in a higher use of cash compared with the third quarter of 2005. The change in non-cash working capital mainly related to a reduction of $242 million in outstanding accounts receivable that had been sold under our securitization program. The debt issuances and repayments presented in the Consolidated Statements of Cash Flows include multiple drawings and repayments under revolving debt facilities.

5.3 INVESTING ACTIVITIES

In the third quarter of 2006, cash used in investing activities amounted to $713 million compared with $776 million in the third quarter of 2005. Cash was used primarily for capital expenditures.

5.4 SOURCES OF CAPITAL

Liquidity describes a company's ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash to fund capital programs necessary to maintain and increase production and proved developed reserves, to acquire strategic oil and gas assets, repay maturing debt and pay dividends. Husky's upstream capital programs are funded principally by cash provided from operating activities. During times of low oil and gas prices, part of a capital program can generally be deferred. However, due to the long cycle times and the importance to future cash flow in maintaining our production, it may be necessary to utilize alternative sources of capital to continue our strategic investment plan during periods of low commodity prices. As a result, we continually examine our options with respect to sources of long and short-term capital resources. In addition, from time to time we engage in hedging a portion of our revenue to protect cash flow.



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

Sources and Uses of Cash Nine months Year ended

ended Sept. 30 December 31

(millions of dollars) 2006 2005

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

Cash sourced

Cash flow from operations(1) $ 3,294 $ 3,785

Asset sales 34 74

Proceeds from exercise of stock options 3 6

Proceeds from monetization of financial

instruments - 39

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

3,331 3,904

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

Cash used

Capital expenditures 2,289 3,068

Debt repayment - net 96 215

Special dividend on common shares - 424

Ordinary dividends on common shares 424 276

Settlement of asset retirement obligations 24 41

Other 12 32

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

2,845 4,056

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

Net cash (deficiency) 486 (152)

Increase (decrease) in non-cash working capital (126) 394

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

Increase in cash and cash equivalents 360 242

Cash and cash equivalents - beginning of period 249 7

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

Cash and cash equivalents - end of period $ 609 $ 249

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

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

(1) Cash flow from operations represents net earnings plus items not

affecting cash, which include accretion, depletion, depreciation and

amortization, future income taxes and foreign exchange.

 


Working capital is the amount by which current assets exceed current liabilities. At September 30, 2006, our working capital deficiency was $600 million compared with $1.0 billion at December 31, 2005. These working capital deficits are primarily the result of accounts payable related to capital expenditures for exploration and development. Settlement of these current liabilities is funded by cash provided by operating activities and to the extent necessary by bank borrowings. This position is a common characteristic of the oil and gas industry which, by the nature of its business, spends large amounts of capital.

At September 30, 2006, we had unused committed long and short-term credit facilities totalling $1.4 billion. A total of $12 million of our borrowing credit facilities were used in support of outstanding letters of credit and an additional $58 million of letters of credit were outstanding at September 30, 2006 and supported by dedicated credit lines. During the second quarter of 2006, our long-term revolving credit facilities were extended from three to five year maturities.

We filed a debt shelf prospectus with the Alberta Securities Commission and the U.S. Securities Exchange Commission on September 21, 2006. The shelf prospectus replaces our shelf prospectus dated August 11, 2004, and will enable us to offer up to U.S. $1 billion of debt securities in the United States until October 21, 2008. During the 25 months that the prospectus is effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale.

Credit Ratings

During the third quarter of 2006, Standard and Poor's Rating Services raised the rating of our long-term corporate credit and senior unsecured debt from BBB to BBB+ with stable outlook.

5.5 CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

Refer to Husky's 2005 annual Management's Discussion and Analysis under the caption "Cash Requirements" which summarizes contractual obligations and commercial commitments. There has been no material change in these amounts as at September 30, 2006.

5.6 OFF BALANCE SHEET ARRANGEMENTS

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

We engage, in the ordinary course of business, in the securitization of accounts receivable. At September 30, 2006, we had no accounts receivable sold under the securitization program. The securitization program permits the sale of a maximum $350 million of accounts receivable on a revolving basis. The accounts receivable are sold to an unrelated third party and in accordance with the agreement we must provide a loss reserve to replace defaulted receivables. The securitization agreement expires on January 31, 2009.

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

6.0 TRANSACTIONS WITH RELATED PARTIES

We did not have any significant transactions with related parties during the first nine months of 2006 or during the year ended December 31, 2005.

7.0 SIGNIFICANT CUSTOMERS

We did not have any customers that constituted more than 10 percent of total sales and operating revenues during the first nine months of 2006.

8.0 FINANCIAL AND DERIVATIVE INSTRUMENTS

Husky is exposed to market risks related to commodity prices, interest rates and foreign exchange rates as discussed under Section 3.0 "Business Environment". From time to time, we use financial and derivative instruments to manage our exposure to these risks.

8.1 POWER CONSUMPTION

At September 30, 2006, we had hedged power consumption as follows:



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

(millions of dollars, Notional

except where Volumes Unrecognized

indicated) (MW) Term Price Gain (Loss)

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

Oct. to

Fixed price purchase 38.0 Dec. 2006 $ 62.95/MWh $ 0.5

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

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

 


8.2 INTEREST RATE RISK MANAGEMENT

In the first nine months of 2006, interest rate risk management activities resulted in a decrease to interest expense of $1 million.

Cross currency swaps resulted in an addition to interest expense of $8 million in the first nine months of 2006.

Husky has interest rate swaps on $200 million of long-term debt effective February 8, 2002 whereby 6.95 percent was swapped for CDOR + 175 bps until July 14, 2009. During the first nine months of 2006, these swaps resulted in an offset to interest expense amounting to $2 million.

The amortization of previous interest rate swap terminations resulted in an additional $7 million offset to interest expense in the first nine months of 2006.

8.3 FOREIGN CURRENCY RISK MANAGEMENT

Please refer to note 11 of the Consolidated Financial Statements.

9.0 APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain of our accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. For a discussion about those accounting policies, please refer to our Management's Discussion and Analysis for the year ended December 31, 2005 available at www.sedar.com.

10.0 NEW ACCOUNTING STANDARDS

Effective January 1, 2006, we adopted the revised recommendations of the Canadian Institute of Chartered Accountants section 3831, "Non-monetary Transactions" which replaced section 3830 of the same name. The new recommendations require that all non-monetary transactions are measured based on fair value unless the transaction lacks commercial substance or is an exchange of product or property held for sale in the ordinary course of business. The guidance was effective for all non-monetary transactions initiated in periods beginning on or after January 1, 2006.



11.0 OUTSTANDING SHARE DATA

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

Nine months Year ended

ended Sept. 30 December 31

(in thousands, except per share amounts) 2006 2005

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

Share price(1)

High $ 83.00 $ 69.95

Low $ 58.00 $ 32.30

Close at end of period $ 71.96 $ 59.00

Average daily trading volume 582 664

Weighted average number of common shares

outstanding

Basic 424,187 423,964

Diluted 424,187 423,964

Issued and outstanding at end of period(2)

Number of common shares 424,255 424,125

Number of stock options 6,038 7,285

Number of stock options exercisable 2,340 1,533

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

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

(1) Trading in the common shares of Husky Energy Inc. ("HSE") commenced

on the Toronto Stock Exchange on August 28, 2000. The Company is

represented in the S&P/TSX Composite, S&P/TSX Canadian Energy Sector

and in the S&P/TSX 60 indices.

(2) There were no significant issuances of common shares, stock options

or any other securities convertible into, or exercisable or

exchangeable for common shares during the period from September 30,

2006 to October 11, 2006.

 


12.0 NON-GAAP MEASURES

Disclosure of Cash Flow from Operations

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

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



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

Nine months Year ended

ended Sept. 30 December 31

(millions of dollars) 2006 2005

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

Non-GAAP

Cash flow from operations $ 3,294 $ 3,785

Settlement of asset retirement obligations (24) (41)

Change in non-cash working capital 617 (72)

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

GAAP

Cash flow - operating activities $ 3,887 $ 3,672

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

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


13.0 TERMS AND 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(1)

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

OPEC Organization of Petroleum Exporting

Countries

WCSB Western Canada Sedimentary Basin

SAGD Steam-assisted gravity drainage

Carbonate Sedimentary rock primarily composed of

calcium carbonate (limestone) or calcium

magnesium carbonate (dolomite) which

forms many petroleum reservoirs

Bitumen A naturally occurring viscous mixture

consisting mainly of pentanes and heavier

hydrocarbons. Its viscosity is greater

than 10 degrees API

Petroleum in Place The total quantity of petroleum that is

estimated to exist originally in

naturally occurring reservoirs. Oil in

place, gas in place and bitumen in place

are defined in the same manner

Coalbed Methane Methane (CH4), the simplest hydrocarbon

deposits adsorbed in the pores of coal

seams

Surfactant A substance that tends to reduce the

surface tension of a liquid in which it

is dissolved

Polymer A substance which has a molecular

structure built up mainly or entirely of

many similar units bonded together

Spider Buoy A buoy moored to the seabed that is pulled

into the bottom of and secured to the

floating production, storage and

offloading vessel. Oil is transferred

through an in-line swivel via a loading

manifold to the piping system of the

vessel. When disconnected the buoy will

float in a position ready for

reconnection

Front-end Engineering Design Preliminary engineering and design

planning, which among other things,

identifies project objectives, scope,

alternatives, specifications, risks,

costs, schedule and economics

FEED Front-end engineering design

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

Cash Flow from Operations Earnings from operations plus non-cash

charges before settlement of asset

retirement obligations and change in

non-cash working capital

Equity Shares and retained earnings

Total Debt Long-term debt including current portion

and bank operating loans

hectare One hectare is equal to 2.47 acres

initial reserves Remaining reserves plus cumulative

production

feedstock Raw materials which are processed into

petroleum products

design rate capacity The maximum continuous rated output of a

plant based on its design

(1) NOVA Inventory Transfer is an exchange or transfer of title of gas

that has been received into the NOVA pipeline system but not yet

delivered to a connecting pipeline.

 


Natural gas converted on the basis that six mcf equals one barrel of oil. In this report, the terms "Husky Energy Inc.", "Husky", "we", "our" or "the Company" mean Husky Energy Inc. and its subsidiaries and partnership interests on a consolidated basis.


14.0 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 may be forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include: our general strategic plans, our production for the Tucker in-situ oil sands project, our Sunrise oil sands project design schedule and water evaluation and stratigraphic drilling plans, our Caribou oil sands drilling plans, our White Rose oil field drilling, development and production plans, the schedule for the Terra Nova oil field's resumption of production, the expected results of our West Bonne Bay drilling program, our plans for prospect mapping for Northwest Territories exploration, our Lloydminster ethanol plant production schedule and planned purchase of grain feedstock, our Minnedosa plant commissioning schedule, the schedule and expected results of our offshore China geophysical and drilling programs, the schedule and our plans for expanding our heavy crude oil mainline and expected results and schedule of our Lloydminster upgrader expansion design plans. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this release and Interim Report. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.

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


- adequacy of and fluctuations in oil and natural gas prices;

- demand for our products and services and the cost of required inputs;

- our ability to replace our reserves;

- competitive actions of other companies, including increased

competition from other oil and gas companies or from companies that

provide alternate sources of energy;

- the occurrence 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;

- actions by governmental authorities, including changes in

environmental and other regulations that may impose restrictions in

areas where we operate; and

- the accuracy of our oil and gas reserve estimates and estimated

production levels as they are affected by our success at exploration

and development drilling and related activities and estimated decline

rates.


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.

15.0 CAUTIONARY NOTE REQUIRED BY NATIONAL INSTRUMENT 51-101

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

Husky's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Husky by Canadian securities regulatory authorities, which permits Husky to provide disclosure required by and consistent with those of the United States Securities and Exchange Commission and the Financial Accounting Standards Board in the United States in place of much of the disclosure expected by National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer to "Disclosure of Exemption Under National Instrument 51-101" at page 2 of our Annual Information Form for the year ended December 31, 2005 filed with securities regulatory authorities for further information.

16.0 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 and Interim Report, such as "estimated resource" and "oil or bitumen in place", 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

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

September 30 December 31

(millions of dollars) 2006 2005

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

(unaudited) (audited)

Assets

Current assets

Cash and cash equivalents $ 609 $ 249

Accounts receivable 1,002 856

Inventories 437 471

Prepaid expenses 62 40

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

2,110 1,616

Property, plant and equipment - (full cost

accounting) 24,642 22,375

Less accumulated depletion, depreciation

and amortization 9,577 8,416

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

15,065 13,959

Goodwill 160 160

Other assets 54 62

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

$ 17,389 $ 15,797

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

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

Liabilities and Shareholders' Equity

Current liabilities

Accounts payable and accrued liabilities $ 2,443 $ 2,391

Long-term debt due within one year (note 5) 267 274

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

2,710 2,665

Long-term debt (note 5) 1,455 1,612

Other long-term liabilities (note 6) 748 730

Future income taxes 3,187 3,270

Commitments and contingencies (note 8)

Shareholders' equity

Common shares (note 9) 3,532 3,523

Retained earnings 5,757 3,997

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

9,289 7,520

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

$ 17,389 $ 15,797

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

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

Common shares outstanding (millions) (note 9) 424.3 424.1

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.

Consolidated Statements of Earnings

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

Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars,

except per share

amounts) (unaudited) 2006 2005 2006 2005

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

Sales and operating

revenues, net of

royalties $ 3,436 $ 2,594 $ 9,580 $ 7,038

Costs and expenses

Cost of sales and

operating expenses 1,944 1,532 5,409 4,014

Selling and

administration

expenses 38 40 115 109

Stock-based compensation 18 79 103 177

Depletion, depreciation

and amortization 411 311 1,173 913

Interest - net (note 5) 19 - 68 16

Foreign exchange (note 5) 5 (63) (32) (36)

Other - net 11 (57) 19 (52)

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

2,446 1,842 6,855 5,141

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

Earnings before income

taxes 990 752 2,725 1,897

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

Income taxes (note 7)

Current 210 78 624 220

Future 98 118 (83) 343

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

308 196 541 563

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

Net earnings $ 682 $ 556 $ 2,184 $ 1,334

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

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

Earnings per share

Basic $ 1.61 $ 1.31 $ 5.15 $ 3.15

Diluted $ 1.61 $ 1.31 $ 5.15 $ 3.15

Weighted average number

of common shares

outstanding (millions)

Basic 424.2 424.0 424.2 423.9

Diluted 424.2 424.0 424.2 423.9

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

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

Consolidated Statements of Retained Earnings

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

Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars)

(unaudited) 2006 2005 2006 2005

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

Beginning of period $ 5,287 $ 3,362 $ 3,997 $ 2,694

Net earnings 682 556 2,184 1,334

Dividends on common

shares (212) (60) (424) (170)

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

End of period $ 5,757 $ 3,858 $ 5,757 $ 3,858

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.

Consolidated Statements of Cash Flows

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

Three months Nine months

ended Sept. 30 ended Sept. 30

(millions of dollars)

(unaudited) 2006 2005 2006 2005

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

Operating activities

Net earnings $ 682 $ 556 $ 2,184 $ 1,334

Items not affecting

cash

Accretion (note 6) 16 8 34 25

Depletion,

depreciation and

amortization 411 311 1,173 913

Future income taxes

(note 7) 98 118 (83) 343

Foreign exchange - (66) (42) (42)

Other 17 17 28 15

Settlement of asset

retirement obligations (10) (10) (24) (24)

Change in non-cash

working capital (note 4) 247 171 617 41

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

Cash flow -

operating activities 1,461 1,105 3,887 2,605

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

Financing activities

Bank operating loans

financing - net - (34) - (49)

Long-term debt issue - 576 1,226 3,027

Long-term debt repayment - (782) (1,322) (3,175)

Proceeds from exercise

of stock options 2 1 3 5

Proceeds from

monetization of

financial instruments - - - 30

Dividends on common

shares (212) (60) (424) (170)

Change in non-cash

working capital (note 4) (123) 9 (664) (211)

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

Cash flow -

financing activities (333) (290) (1,181) (543)

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

Available for investing 1,128 815 2,706 2,062

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

Investing activities

Capital expenditures (746) (805) (2,289) (2,109)

Asset sales 1 13 34 70

Other 1 (21) (12) (23)

Change in non-cash

working capital (note 4) 31 37 (79) 35

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

Cash flow -

investing activities (713) (776) (2,346) (2,027)

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

Increase in cash and

cash equivalents 415 39 360 35

Cash and cash equivalents

at beginning of period 194 3 249 7

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

Cash and cash equivalents

at end of period $ 609 $ 42 $ 609 $ 42

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

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

The accompanying notes to the consolidated financial statements are an

integral part of these statements.


Notes to the Consolidated Financial Statements

Nine months ended September 30, 2006 (unaudited)

Except where indicated and per share amounts, all dollar amounts are in

millions.


Note 1 Segmented Financial Information

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

Upstream Midstream

Infrastructure

Upgrading and Marketing

2006 2005 2006 2005 2006 2005

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

Three months ended

Sept. 30

Sales and operating

revenues, net of

royalties $ 1,600 $ 1,176 $ 485 $ 328 $ 2,451 $ 1,808

Costs and expenses

Operating, cost

of sales, selling

and general 329 262 399 283 2,396 1,752

Depletion,

depreciation and

amortization 382 280 6 6 6 5

Interest - net - - - - - -

Foreign exchange - - - - - -

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

711 542 405 289 2,402 1,757

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

Earnings (loss)

before income taxes 889 634 80 39 49 51

Current income

taxes 158 47 31 4 18 (3)

Future income

taxes 123 142 (5) 8 (2) 20

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

Net earnings (loss) $ 608 $ 445 $ 54 $ 27 $ 33 $ 34

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

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

Capital expenditures

- Three months

ended Sept. 30 $ 612 $ 701 $ 44 $ 38 $ 29 $ 11

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

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

Nine months ended

Sept. 30

Sales and operating

revenues, net of

royalties $ 4,338 $ 3,040 $ 1,294 $ 1,074 $ 7,182 $ 4,871

Costs and expenses

Operating, cost

of sales, selling

and general 948 751 980 727 6,958 4,657

Depletion,

depreciation and

amortization 1,087 831 18 15 17 16

Interest - net - - - - - -

Foreign exchange - - - - - -

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

2,035 1,582 998 742 6,975 4,673

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

Earnings (loss)

before income taxes 2,303 1,458 296 332 207 198

Current income

taxes 457 169 84 13 57 (14)

Future income

taxes 4 298 (14) 88 (1) 83

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

Net earnings (loss) $ 1,842 $ 991 $ 226 $ 231 $ 151 $ 129

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

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

Capital employed

- As at Sept. 30 $ 9,229 $ 8,005 $ 502 $ 489 $ 578 $ 670

Capital

expenditures

- Nine months

ended Sept. 30 $ 1,923 $ 1,899 $ 119 $ 85 $ 41 $ 24

Total assets

- As at Sept. 30 $13,531 $11,920 $ 943 $ 806 $ 1,093 $ 1,042

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

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

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

Corporate and

Refined Products Eliminations(1) Total

2006 2005 2006 2005 2006 2005

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

Three months ended

Sept. 30

Sales and operating

revenues, net of

royalties $ 776 $ 716 $(1,876) $(1,434) $ 3,436 $ 2,594

Costs and expenses

Operating, cost

of sales, selling

and general 724 660 (1,837) (1,363) 2,011 1,594

Depletion,

depreciation and

amortization 11 14 6 6 411 311

Interest - net - - 19 - 19 -

Foreign exchange - - 5 (63) 5 (63)

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

735 674 (1,807) (1,420) 2,446 1,842

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

Earnings (loss)

before income taxes 41 42 (69) (14) 990 752

Current income

taxes 5 (1) (2) 31 210 78

Future income

taxes 8 16 (26) (68) 98 118

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

Net earnings (loss) $ 28 $ 27 $ (41) $ 23 $ 682 $ 556

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

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

Capital expenditures

- Three months

ended Sept. 30 $ 59 $ 57 $ 10 $ 6 $ 754 $ 813

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

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

Nine months ended

Sept. 30

Sales and operating

revenues, net of

royalties $ 1,996 $ 1,713 $(5,230) $(3,660) $ 9,580 $ 7,038

Costs and expenses

Operating, cost

of sales, selling

and general 1,831 1,577 (5,071) (3,464) 5,646 4,248

Depletion,

depreciation and

amortization 34 34 17 17 1,173 913

Interest - net - - 68 16 68 16

Foreign exchange - - (32) (36) (32) (36)

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

1,865 1,611 (5,018) (3,467) 6,855 5,141

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

Earnings (loss)

before income taxes 131 102 (212) (193) 2,725 1,897

Current income

taxes 17 (3) 9 55 624 220

Future income

taxes 18 40 (90) (166) (83) 343

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

Net earnings (loss) $ 96 $ 65 $ (131) $ (82) $ 2,184 $ 1,334

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

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

Capital employed

- As at Sept. 30 $ 705 $ 402 $ (3) $ (290) $11,011 $ 9,276

Capital

expenditures

- Nine months

ended Sept. 30 $ 202 $ 105 $ 23 $ 14 $ 2,308 $ 2,127

Total assets

- As at Sept. 30 $ 1,070 $ 783 $ 752 $ 161 $17,389 $14,712

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

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

(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.

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, 2005, 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, 2005.



Note 3 Change in Accounting Policies

Non-monetary Transactions

Effective January 1, 2006, the Company adopted the revised

recommendations of the Canadian Institute of Chartered Accountants

section 3831, "Non-monetary Transactions" which replaced section 3830 of

the same name. The new recommendations require that all non-monetary

transactions are measured based on fair value unless the transaction

lacks commercial substance or is an exchange of product or property held

for sale in the ordinary course of business. The guidance was effective

for all non-monetary transactions initiated in periods beginning on or

after January 1, 2006.

 


Note 4 Cash Flows - Change in Non-cash Working Capital

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

Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

a) Change in non-cash

working capital was

as follows:

Decrease (increase)

in non-cash working

capital

Accounts receivable $ (255) $ (93) $ (146) $ (113)

Inventories 28 (36) 34 (176)

Prepaid expenses (1) 15 (20) (3)

Accounts payable and

accrued liabilities 383 331 6 157

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

Change in non-cash

working capital 155 217 (126) (135)

Relating to:

Financing activities (123) 9 (664) (211)

Investing activities 31 37 (79) 35

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

Operating activities $ 247 $ 171 $ 617 $ 41

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

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

b) Other cash flow

information:

Cash taxes paid

(received) $ (10) $ (14) $ 163 $ 145

Cash interest paid $ 22 $ 30 $ 101 $ 103

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

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

Note 5 Long-term Debt

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

Sept. 30 Dec. 31 Sept. 30 Dec. 31

Maturity 2006 2005 2006 2005

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

Cdn $ Amount U.S. $ Denominated

Long-term debt

7.125% notes 2006 $ 167 $ 175 $ 150 $ 150

6.25% notes 2012 446 467 400 400

7.55% debentures 2016 223 233 200 200

6.15% notes 2019 335 350 300 300

8.45% senior secured

bonds - 99 - 85

Medium-term notes 2007-9 300 300 - -

8.90% capital

securities 2028 251 262 225 225

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

Total long-term debt 1,722 1,886 $ 1,275 $ 1,360

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

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

Amount due within one year (267) (274)

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

$ 1,455 $ 1,612

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

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

Interest - net consisted of:

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

Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

Long-term debt $ 32 $ 35 $ 100 $ 105

Short-term debt 1 1 4 3

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

33 36 104 108

Amount capitalized (9) (36) (30) (91)

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

24 - 74 17

Interest income (5) - (6) (1)

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

$ 19 $ - $ 68 $ 16

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

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

Foreign exchange consisted of:

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

Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

Gain on translation of

U.S. dollar denominated

long-term debt $ - $ (89) $ (67) $ (58)

Cross currency swaps - 22 26 16

Other losses 5 4 9 6

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

$ 5 $ (63) $ (32) $ (36)

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

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



On September 21, 2006, Husky filed a shelf prospectus, which replaces the

Company's shelf prospectus dated August 11, 2004, and will enable Husky

to offer up to U.S. $1.0 billion of debt securities in the United States

until October 21, 2008. During the 25-month period that the prospectus

remains effective, debt securities may be offered in amounts, at prices

and on terms to be determined based on market conditions at the time of

sale and set forth in an accompanying prospectus supplement. As at

September 30, 2006, there were no debt securities issued under this new

shelf prospectus.


Note 6 Other Long-term Liabilities

Asset Retirement Obligations

Changes to asset retirement obligations were as follows:

 


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

Nine months

ended Sept. 30

2006 2005

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

Asset retirement obligations at beginning of

period $ 557 $ 509

Liabilities incurred 29 13

Liabilities disposed - (7)

Liabilities settled (24) (24)

Accretion 34 25

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

Asset retirement obligations at end of period $ 596 $ 516

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

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



At September 30, 2006, the estimated total undiscounted inflation

adjusted amount required to settle the asset retirement obligations was

$3.5 billion. These obligations will be settled based on the useful lives

of the underlying assets, which currently extend up to 50 years into the

future. This amount has been discounted using credit adjusted risk free

rates ranging from 6.2 to 6.4 percent.


Note 7 Income Taxes


There were no tax rate benefits recorded during the third quarter of 2006

or 2005. In the second quarter of 2006, a recovery of future taxes

resulted from recording non-recurring tax benefits of $328 million that

arose due to changes in the tax rates for the governments of Canada

($198 million), Alberta ($90 million) and Saskatchewan ($40 million). All

of this tax legislation received royal assent and was, therefore,

substantively enacted in the second quarter of 2006.


Note 8 Commitments and Contingencies


The Company has no material litigation other than various claims and

litigation arising in the normal course of business. While the outcome of

these matters is uncertain and there can be no assurance that such

matters will be resolved in the Company's favour, the Company does not

currently believe that the outcome of adverse decisions in any pending or

threatened proceedings related to these and other matters or any amount

which it may be required to pay by reason thereof would have a material

adverse impact on its financial position, results of operations or

liquidity.


Note 9 Share Capital


The Company's authorized share capital consists of an unlimited number of

no par value common and preferred shares.

Common Shares


Changes to issued common shares were as follows:

 


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

Nine months ended September 30

2006 2005

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

Number of Number of

Shares Amount Shares Amount

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

Balance at beginning

of period 424,125,078 $ 3,523 423,736,414 $ 3,506

Exercised - options and

warrants 129,765 9 375,136 16

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

Balance at September 30 424,254,843 $ 3,532 424,111,550 $ 3,522

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

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

Stock Options

A summary of the status of the Company's stock option plan is presented

below:

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

Nine months ended September 30

2006 2005

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

Weighted Weighted

Number of Average Number of Average

Options Exercise Options Exercise

(thousands) Prices (thousands) Prices

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

Outstanding, beginning of

period 7,285 $ 25.81 9,964 $ 22.61

Granted 742 $ 70.25 405 $ 43.19

Exercised for common shares (130) $ 22.18 (346) $ 15.62

Surrendered for cash (1,641) $ 23.51 (2,241) $ 18.53

Forfeited (218) $ 40.48 (441) $ 24.01

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

Outstanding at September 30 6,038 $ 31.45 7,341 $ 25.23

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

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

Options exercisable at

September 30 2,340 $ 24.14 1,557 $ 23.47

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

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

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

September 30, 2006

Outstanding Options Options Exercisable

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

Weighted

Average

Weighted Contract- Weighted

Number of Average ual Number of Average

Range of Options Exercise Life Options Exercise

Exercise Price (thousands) Prices (years) (thousands) Prices

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

$13.96 - $14.99 69 $ 14.58 1 69 $ 14.58

$15.00 - $22.99 125 $ 20.13 2 49 $ 18.81

$23.00 - $23.99 4,413 $ 23.83 3 2,114 $ 23.83

$24.00 - $39.99 330 $ 32.15 3 64 $ 31.71

$40.00 - $55.99 404 $ 52.17 4 44 $ 48.63

$56.00 - $73.80 697 $ 71.00 5 - $ -

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

6,038 $ 31.45 3 2,340 $ 24.14

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

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

Note 10 Employee Future Benefits

Total benefit costs recognized were as follows:

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

Three months Nine months

ended Sept. 30 ended Sept. 30

2006 2005 2006 2005

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

Employer current service

cost $ 4 $ 4 $ 13 $ 13

Interest cost 2 2 7 7

Expected return on plan

assets (1) (2) (4) (6)

Amortization of net

actuarial losses - 1 - 2

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

$ 5 $ 5 $ 16 $ 16

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

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

Note 11 Financial Instruments and Risk Management

Unrecognized gains (losses) on derivative instruments were as follows:

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

Sept. 30 Dec. 31

2006 2005

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

Commodity price risk management

Power consumption $ 1 $ -

Interest rate risk management

Interest rate swaps 6 7

Foreign currency risk management

Foreign exchange contracts (31) (32)

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

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

Commodity Price Risk Management

Power Consumption

At September 30, 2006, the Company had hedged power consumption as

follows:

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

Notional Volumes

(MW) Term Price

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

Fixed price purchase 38.0 Oct. to Dec. 2006 $62.95/MWh

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

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

The impact of the hedge program during the first nine months of 2006 was

a gain of $1 million (2005 - gain of $1 million).

Natural Gas Contracts

At September 30, 2006, the unrecognized gains (losses) on external

offsetting physical purchase and sale natural gas contracts were as

follows:

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

Volumes Unrecognized

(mmcf) Gain (Loss)

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

Physical purchase contracts 30,583 $ 3

Physical sale contracts (30,583) $ 2

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

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

/T/

Interest Rate Risk Management

During the first nine months of 2006, the Company realized a gain of

$1 million (2005 - gain of $11 million) from interest rate risk

management activities.

Foreign Currency Risk Management

During the first nine months of 2006, the Company realized a loss of

$22 million (2005 - loss of $4 million) from all foreign currency risk

management activities.

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

September 30, 2006, no accounts receivable had been sold under the

program compared with $350 million in outstanding accounts receivable

sold at December 31, 2005.

Husky Energy Inc. will host a conference call for analysts and investors

on Friday, October 20, 2006 at 4:15 p.m. Eastern time to discuss Husky's

third quarter results. To participate please dial 1-800-289-6406

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.

Those unable to listen to the call live may listen to a recording by

dialing 1-800-558-5253 one hour after the completion of the call,

approximately 5:30 p.m. (EST), then dialing reservation number 21306700.

The Postview will be available until Monday, November 20, 2006.

Media are invited to listen to the conference call by dialing

1-800-377-5794 beginning at 4:05 p.m. Eastern time.



FOR FURTHER INFORMATION PLEASE CONTACT:

Husky Energy Inc.
Tanis Thacker
Senior Analyst, 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