Husky Energy Reports 2008 First Quarter Results
CALGARY, ALBERTA -- (MARKET WIRE) -- 04/21/08 -- Husky Energy Inc. (TSX: HSE) reported net earnings of $887 million or $1.04 per share (diluted) in the first quarter of 2008, an increase of 36% from $650 million or $0.77 per share (diluted) in the same quarter of 2007. Cash flow from operations in the first quarter was $1,541 million or $1.82 per share (diluted), a 16% increase compared with $1,324 million or $1.56 per share (diluted) in the same quarter of 2007. Sales and operating revenues, net of royalties, were $5.1 billion in the first quarter of 2008, up 57% compared with $3.2 billion in the first quarter of 2007.
"Husky has continued to achieve good financial results in revenue, net earnings and cash flow from operations in a high oil commodity price environment," said Mr. John C.S. Lau, President & Chief Executive Officer of Husky Energy Inc. "In the first quarter, we are pleased to have closed the transaction with BP on schedule, creating an integrated oil sands/refining joint venture and to have received government and regulatory approvals to proceed with the development of the North Amethyst oil field offshore Canada's East Coast." In the first quarter of 2008, total production averaged 350,100 barrels of oil equivalent per day compared with 390,000 barrels of oil equivalent per day in the first quarter of 2007. Total crude oil and natural gas liquids production was 251,700 barrels per day, compared with 283,300 barrels per day in the first quarter of 2007. The decline is due primarily to a 13-day turnaround at the White Rose oil field in late January and early February and the sale of some non-core properties in Western Canada. Natural gas production was 590.4 million cubic feet per day compared with 640.0 million cubic feet per day in the same period of 2007, which reflects the decrease in wells drilled in 2007 as a result of weak gas prices.
On March 31, 2008, Husky and BP completed all agreements required to form an integrated oil sands joint venture. The transaction consists of a 50/50 partnership to develop the Sunrise oil sands project in Canada, which Husky will operate, and a 50/50 limited liability company for the existing Toledo refinery in Ohio, USA, which BP will operate. The development of the Sunrise oil sands project is expected to proceed in three phases. The first development phase will produce 60,000 barrels per day of bitumen starting in 2012 and the second and third phases are targeted to increase the Sunrise production capacity to approximately 200,000 barrels per day of bitumen by 2015 to 2020. The Toledo refinery will be modified to process approximately 120,000 barrels per day of bitumen feedstock by 2015, matching the first two phases of the Sunrise oil sands development. Agreement to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central Athabasca oil sands deposit, for $105 million was closed in the first quarter. Husky has a 100% working interest in these oil sands leases. This land lies adjacent to oil sands leases that we currently hold. In April 2008, the Company received approval from the federal and provincial governments and regulators for the North Amethyst satellite development near the White Rose oil field. The North Amethyst oil field is the first of three satellite oil pools to be developed adjacent to the White Rose oil field in the Jeanne d'Arc Basin, with first oil planned for late 2009 or early 2010. Husky's working interest in this development is 68.875%. Husky entered into contracts for two offshore drilling rigs in the first quarter to drill several development wells in the White Rose and satellite oil fields as well as exploration prospects in the Jeanne d'Arc Basin. In January 2008, Husky announced that it had contracted the GSF Grand Banks semi-submersible drilling rig until January 2011. In March 2008, agreement was reached with our partners to bring the semi-submersible drilling rig, Henry Goodrich, to the Newfoundland and Labrador offshore region. The rig will be available for approximately 17 months for Husky operated wells. In March 2008 we reached an agreement to participate in an exploration well to be drilled later in 2008 in the Flemish Pass Basin off the east coast of Newfoundland and Labrador on Exploration Licence 1049 operated by StatoilHydro. Husky has a 35% working interest in this licence. Internationally, Husky completed the interpretation of the 3-D seismic data acquired over the Liwan natural gas discovery offshore China in preparation for the arrival of the West Hercules deep water drilling rig in mid-2008. Husky plans to drill one shallow water exploration well on Block 39/05 before moving the rig to Block 29/26 to commence delineation drilling of the Liwan discovery. Elsewhere in China, Husky has spudded an exploration well in the Beibu Basin on Block 23/15 and we should soon complete the acquisition of 750 square kilometres of 3-D seismic data on Block 35/18 in the Yinggehai Basin. In April 2008, the Company completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. Under the agreement, CNOOC Ltd. acquired a 50% equity interest in Husky Oil (Madura) Limited for a consideration of U.S. $125 million. Husky Oil (Madura) Limited holds a 100% interest in the Madura Strait Production Sharing Contract ("PSC"). The agreement covers the development and further exploration of the Madura Strait PSC. Husky has drilled 10 wells in this area since 1984 and made two discoveries, the Madura BD and MDA gas fields. At the Lima Refinery, Husky has completed the acquisition transaction and assumed responsibility for all operations and administrative, marketing and trading services. In addition, a sales and marketing office has been established in Columbus, Ohio, USA to manage product sales and movements in our U.S. operations. In Minnedosa, the ethanol plant that was commissioned in December 2007 reached its design capacity of 130 million litres per year during the first quarter. Husky continues to strengthen its balance sheet and financial position. Total long-term debt including current portion at March 31, 2008 was $3,019 million compared with $2,814 million at December 31, 2007. Debt to cash flow ratio and debt to capital employed ratio remained low at 0.5 and 20% respectively at March 31, 2008. MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") APRIL 21, 2008 ---------------------------------------------------------------------------Table of Contents 1. Quarterly Financial Results 6. Risk Management 2. Capability to Deliver Results and 7. Critical Accounting Estimates Strategic Plan 3. Key Performance Drivers 8. Changes in Accounting Policies 4. Results of Operations 9. Outstanding Share Data 5. Liquidity and Capital Resources 10.Reader Advisories ------------------------------------------------------------------------------------------------------------------------------------------------------ Husky's Businesses Husky is a Canadian-based energy and energy-related company with total assets greater than $24 billion and over 4,000 employees. Husky is integrated through the three industry sectors: upstream, midstream and downstream. - In the upstream sector, we explore for, develop and produce crude oil and natural gas (upstream business segment). - In the midstream sector, we upgrade heavy crude oil (upgrading business segment), process and pipeline heavy crude oil, maintain interests in two cogeneration plants as well as store and market crude oil and natural gas (infrastructure and marketing business segment). - In the downstream sector, we distribute motor fuel and ancillary and convenience products, manufacture and market asphalt products, produce ethanol and operate two regional refineries in Canada (Canadian refined products business segment) and refine crude oil in two refineries in Ohio and market refined products in the U.S. Midwest (U.S. refining and marketing business segment). 1. Quarterly Financial Results ----------------------------------------------------------------------------Quarterly Financial Summary Three months ended (millions of dollars, March 31 Dec. 31 Sept. 30 June 30 except per share amounts and ratios) 2008 2007 2007 2007 ----------------------------------------------------------------------------Sales and operating revenues, net of royalties $ 5,086 $ 4,760 $ 4,351 $ 3,163 Segmented net earnings Upstream $ 717 $ 864 $ 516 $ 636 Midstream 144 218 129 77 Downstream 38 103 121 53 Corporate and eliminations (12) (111) 3 (45) ----------------------------------------------------------------------------Net earnings $ 887 $ 1,074 $ 769 $ 721 -------------------------------------------------------------------------------------------------------------------------------------------------------- Per share - Basic and diluted $ 1.04 $ 1.26 $ 0.91 $ 0.85 Cash flow from operations 1,541 1,425 1,420 1,257 Per share - Basic and diluted 1.82 1.68 1.67 1.48 Ordinary quarterly dividend per common share 0.33 0.33 0.25 0.25 Special dividend per common share - - - -Total assets 24,391 21,697 20,718 17,969Total long-term debt including current portion 3,019 2,814 2,835 1,423 Return on equity (1) (percent) 26.8 30.2 26.6 27.1 Return on average capital employed (1) (percent) 22.3 25.7 22.3 23.8 -------------------------------------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------Quarterly Financial Summary Three months ended March 31 Dec. 31 Sept. 30 June 30 (millions of dollars, except per share amounts and ratios) 2007 2006 2006 2006 ----------------------------------------------------------------------------Sales and operating revenues, net of royalties $ 3,244 $ 3,084 $ 3,436 $ 3,040 Segmented net earnings Upstream $ 580 $ 453 $ 608 $ 822 Midstream 111 105 87 140 Downstream 20 10 28 52 Corporate and eliminations (61) (26) (41) (36) ---------------------------------------------------------------------------Net earnings $ 650 $ 542 $ 682 $ 978 ------------------------------------------------------------------------------------------------------------------------------------------------------ Per share - Basic and diluted $ 0.77 $ 0.64 $ 0.80 $ 1.15 Cash flow from operations 1,324 1,207 1,224 1,103 Per share - Basic and diluted 1.56 1.42 1.44 1.30 Ordinary quarterly dividend per common share 0.25 0.25 0.25 0.125 Special dividend per common share 0.25 - - -Total assets 17,781 17,933 17,324 16,328 Total long-term debt including current portion 1,527 1,611 1,722 1,722 Return on equity (1) (percent) 32.1 31.8 34.2 34.8 Return on average capital employed (1) (percent) 27.3 27.0 28.7 28.2 ------------------------------------------------------------------------------------------------------------------------------------------------------(1) Calculated for the 12 months ended for the dates shown. 2. Capability to Deliver Results and Strategic Plan Our current capacity to deliver results and strategic plan are described in our recently filed MD&A and also in our Annual Information Form that are available from www.sedar.com and www.sec.gov. In summary, our strategy is to continue to exploit our oil and gas asset base in Western Canada while expanding into new areas with large scale sustainable growth potential. Our plans include projects in the Alberta oil sands, the basins off the East Coast of Canada, the central Mackenzie River Valley, the South China Sea, Madura Strait, the East Java Sea and offshore Greenland. In the Midstream and Downstream sectors we are enhancing performance and capturing new value throughout the value chain by further integrating our businesses, optimizing our plant operations and expanding plant and infrastructure. 3. Key Performance Drivers To achieve corporate strategic objectives and provide our shareholders with a good return on investment, we need to capture opportunities that will drive corporate performance and enhance our position to continue to capture future opportunities. During the first quarter of 2008, key performance drivers that emerged or were advanced are noted below: 3.1 Across Segments Integrated Oil Sands Joint Development On March 31, 2008, Husky and BP completed contracts that formed an integrated oil sands joint venture. The transaction consists of a 50/50 partnership to develop the Sunrise oil sands project in the Athabasca oil sands deposit, which Husky will operate, and the formation of a 50/50 limited liability company for the existing Toledo, Ohio BP refinery, which BP will operate. The development of the Sunrise oil sands project is expected to proceed in three phases. The first development phase will produce 60 mbbls/day of bitumen starting in 2012 and the second and third phases are targeted to increase the Sunrise production capacity to approximately 200 mbbls/day of bitumen by 2015 to 2020. The Toledo refinery will be modified to process approximately 120 mbbls/day of bitumen feedstock (diluted as required for transportation purposes) by 2015, matching the first two phases of the Sunrise oil sands development. 3.2 Upstream White Rose Development and Delineation Approval of the North Amethyst development application by the Canada - Newfoundland and Labrador Offshore Petroleum Board ("CNLOPB") and the provincial and federal governments was received in April 2008. The front-end engineering design and the glory hole to accommodate the subsea facilities are complete. A drilling rig has been secured and procurement of long lead equipment is underway. West White Rose delineation results continue to be analyzed and infrastructure details and the glory hole location are being determined. The South White Rose extension development plan was approved by the federal and provincial governments in September 2007. In March 2008, agreement was reached with our partners, StatoilHydro and Petro-Canada, to bring the semi-submersible drilling rig Henry Goodrich to the Newfoundland and Labrador offshore region. The rig will be available to us and our partners for 27 months, of which approximately 17 months is for Husky operated wells. We have also contracted the GSF Grand Banks semi-submersible drilling rig until January 2011. These rigs will drill several development wells in the White Rose and satellite fields, including the North Amethyst and West White Rose fields as well as exploration prospects in the Jeanne d'Arc Basin. The Henry Goodrich is also scheduled to drill two development wells in the Terra Nova field. East Coast Exploration Acquisition of 3-D seismic covering 2,500 square kilometres around the White Rose field and on Exploration Licences 1090 and 1091 is scheduled for mid-2008. In March 2008, we reached an agreement to participate in an exploration well to be drilled later in 2008 on Exploration Licence 1049 in the Flemish Pass Basin off the east coast of Newfoundland and Labrador. StatoilHydro is the operator of this licence and we hold a 35% working interest. Tucker Oil Sands Project Optimization strategies intended to remedy performance issues are continuing on the existing well pads. The drilling of eight new well pairs on Pad C is complete and a new D pad with well pairs placed in an optimized position in the reservoir is being planned. Sunrise Oil Sands Project At Sunrise, work on area infrastructure and site preparation progressed during the first quarter. Front-end engineering design activities for Phase 1 are now complete and the project is being readied for sanction. The winter stratigraphic well drilling program is complete and analysis of results is underway. Regulatory amendment approval and the Sunrise project corporate sanction are expected later in 2008. Caribou Technical and field work is continuing on the 10 mbbls/day demonstration project including water source and disposal well and stratigraphic test wells. Regulatory approval for the project is expected in 2008. Saleski The winter drilling program was completed and consisted of a water source and disposal well and seven observation and stratigraphic test wells. We are continuing to work on reservoir characterization and evaluation of various recovery processes. Northwest Territories Exploration Husky holds interests in 4,380 square kilometres in the Central Mackenzie Valley. Two exploration wells were drilled on Exploration License ("EL") 423. The Dahadinni B-20 and the Keele River L-52 wells have both been abandoned without testing. EL 423 is located approximately 60 kilometres southeast of the Summit Creek B-44 and the Stewart Creek D-57 discovery wells. We hold a 75% working interest in EL 423. China Exploration A four well delineation program of the Liwan area on Block 29/26 is on schedule to commence in mid-2008 upon the arrival of the West Hercules deep water drilling rig, which is nearing completion in South Korea and is expected to commence sea trials in May. Three exploration wells are planned to be drilled in the shallow waters of the South and East China seas. The Wushi 23-2-1 well was spudded on March 27, 2008 on Block 23/15 in the Beibu Wan Basin of the South China Sea north of Hainan Island. The second well is expected to spud on Block 39/05 southwest of the Wenchang oil field in the South China Sea before the end of 2008. The third well is slated to be drilled on Block 4/35 in the East China Sea. In February, we commenced acquiring 750 square kilometres of 3-D seismic data on Block 35/18, which is west of Hainan Island in the Yinggehai Basin. In April 2008, we commenced acquiring 725 square kilometres of 3-D seismic on Block 29/06 adjacent to the eastern boundary of Block 29/26 and resumed the acquisition of the remaining 200 square kilometres of 3-D seismic of a 2,615 square kilometre program that was started in 2007 in the Liwan area. Indonesia Exploration and Development We have submitted the Madura BD field development plan and Production Sharing Licence extension to the Indonesian regulatory authorities for approval. Front-end engineering design for the project will begin upon receipt of these regulatory approvals. In April 2008, the Company completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. Under the agreement, CNOOC Ltd. acquired a 50% equity interest in Husky Oil (Madura) Limited for a consideration of U.S. $125 million. Husky Oil (Madura) Limited holds a 100% interest in the Madura Strait Production Sharing Contract ("PSC"). The agreement covers the development and further exploration of the Madura Strait PSC. Analysis is progressing on 1,410 square kilometres of 3-D seismic data recently acquired from the East Bawean II block in the East Java Sea. Currently, two exploration wells are planned for 2009. Land Acquisition Offshore Greenland We hold interests in 34,280 square kilometres in three blocks offshore Greenland. Acquisition of 2-D seismic data is planned for 2008. A hi-resolution aero-gravity and magnetic survey is scheduled for completion in 2008. 3.3 Downstream Lima Refinery in Ohio An engineering evaluation is underway to determine the optimal reconfiguration of the Lima refinery to increase its capacity to process heavier crude feedstocks. BP/Husky Toledo Refinery The acquisition of a 50% interest in the BP Toledo refinery was closed on March 31, 2008. The refinery has the capacity to process 150 mbbls/day of crude oil including 60 mbbls/day of blended heavy sour crude. BP and Husky are planning to convert this refinery to process bitumen feedstock in conjunction with their investment in the Sunrise oil sands project. 4. Results of Operations The following table shows our net earnings by industry sector and includes corporate expenses and intersegment profit eliminations. Quarterly Segmented Net Earnings 4.1 Upstream ----------------------------------------------------------------------------Upstream Net Earnings Summary Three months ended March 31 (millions of dollars) 2008 2007 ----------------------------------------------------------------------------Gross revenues $ 2,253 $ 1,763 Royalties 424 198 ----------------------------------------------------------------------------Net revenues 1,829 1,565 Operating and administration expenses 384 323 Depletion, depreciation and amortization 390 399 Other 29 -Income taxes 309 263 ----------------------------------------------------------------------------Net earnings $ 717 $ 580 -------------------------------------------------------------------------------------------------------------------------------------------------------- Net Revenue During the first quarter of 2008, upstream net revenues increased by $264 million compared with the same period in 2007. Higher crude oil and natural gas prices more than offset lower sales volume during the first quarter of 2008. The Upstream Business Environment Commodity Prices As an integrated producer, profitability is largely determined by realized prices for crude oil and natural gas and refinery processing margins including the effect of changes in the U.S./Canadian dollar exchange rate. All of our crude oil production and the majority of our natural gas production receive the prevailing market price. The price for crude oil is determined mainly by global factors and is beyond our control. The price for natural gas is determined more by the North America fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. Weather conditions also have a dramatic effect on short-term supply and demand. ----------------------------------------------------------------------------Average Benchmark Prices and U.S. Exchange Rate Three months ended March 31 Dec. 31 Sept. 30 June 30 March 31 2008 2007 2007 2007 2007 ----------------------------------------------------------------------------WTI crude oil (1) (U.S. $/bbl) 97.90 90.68 75.38 65.03 58.16 Brent crude oil (2) (U.S. $/bbl) 96.90 88.70 74.87 68.76 57.75 Canadian light crude 0.3% sulphur ($/bbl) 98.20 87.19 80.70 72.61 67.76 Lloyd heavy crude oil @ Lloydminster ($/bbl) 64.23 42.03 43.61 39.02 38.25 NYMEX natural gas (1) (U.S. $/mmbtu) 8.03 6.97 6.16 7.55 6.77 NIT natural gas ($/GJ) 6.76 5.69 5.31 6.99 7.07 WTI/Lloyd crude blend differential (U.S. $/bbl) 21.81 34.06 23.50 20.36 17.32 U.S./Canadian dollar exchange rate (U.S. $) 0.996 1.018 0.957 0.911 0.854 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Prices quoted are near-month contract prices for settlement during the next month. (2) Dated Brent prices which are dated less than 15 days prior to loading for delivery. Crude Oil The following graph illustrates the relative changes over several quarters in the realized prices of our three main crude oil categories expressed in U.S. dollars and West Texas Intermediate ("WTI"), the main benchmark crude oil. WTI and Husky Average Crude Oil Prices The majority of our crude oil production is marketed in North America. The slow economic growth in the United States during the first quarter of 2008 has marginally reduced consumption of petroleum, however, tight production surplus has continued to push crude oil prices to new highs. During March 2008, WTI averaged $105.42/bbl. From December 2007 to March 2008 our monthly average heavy oil prices increased by approximately 52%. Natural Gas The following graph illustrates the relative changes over several quarters in our natural gas price realized compared with two major benchmark prices. NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices Natural gas prices quoted on the NYMEX rose through the first quarter of 2008 and were, on average, 19% higher than the same period in 2007. Higher prices in the first quarter of 2008 are largely attributed to colder weather compared with last winter in the major natural gas consumption regions. At the end of the first quarter of 2008 natural gas stocks in underground storage in the United States were 20% lower than at the same date in 2007. The average prices realized during the first quarter of 2008 compared with the first quarter of 2007 are illustrated below. ----------------------------------------------------------------------------Average Sales Prices Three months ended March 31 2008 2007 ----------------------------------------------------------------------------Crude Oil ($/bbl) Light crude oil & NGL $ 95.20 $ 64.88 Medium crude oil 74.30 46.40 Heavy crude oil & bitumen 63.91 37.63 Total average 79.98 52.70 Natural Gas ($/mcf) Average 7.04 6.94 -------------------------------------------------------------------------------------------------------------------------------------------------------- Oil and Gas Production The following table shows our gross daily production rate by location and product type for five sequential quarters. ----------------------------------------------------------------------------Daily Gross Production Three months ended March 31 Dec. 31 Sept. 30 June 30 March 31 2008 2007 2007 2007 2007 ----------------------------------------------------------------------------Crude oil & NGL (mbbls/day) Western Canada Light crude oil & NGL 25.4 25.8 25.1 25.3 30.1 Medium crude oil 26.9 27.0 26.7 26.8 27.5 Heavy crude oil & bitumen 104.3 107.8 106.5 105.4 108.0 ---------------------------------------------------------------------------- 156.6 160.6 158.3 157.5 165.6 East Coast Canada White Rose - light crude oil 67.5 81.1 79.2 90.3 89.4 Terra Nova - light crude oil 14.9 11.6 16.3 15.5 14.7 China Wenchang - light crude oil & NGL 12.7 11.2 12.7 13.2 13.6 ---------------------------------------------------------------------------- 251.7 264.5 266.5 276.5 283.3 ----------------------------------------------------------------------------Natural gas (mmcf/day) 590.4 617.8 620.1 615.7 640.0 ----------------------------------------------------------------------------Total (mboe/day) 350.1 367.5 369.9 379.1 390.0 -------------------------------------------------------------------------------------------------------------------------------------------------------- Crude Oil and NGL Production Crude oil and NGL production in the first quarter of 2008 decreased by 11% compared with the same period in 2007. Production from the White Rose field was shut down for 13 days in the quarter while scheduled maintenance was performed on the SeaRose FPSO. Production from White Rose averaged 67 mbbls/day at an average realized price of $97.96/bbl during the first quarter of 2008 compared with 89 mbbls/day at an average realized price of $66.69/bbl during the same period in 2007. In March 2008, the Tier II incremental royalty rate became effective for White Rose. The Tier II status increases royalty rates by 10%. During the first quarter of 2008, crude oil and NGL production from Western Canada was down 5% compared with the first quarter of 2007 primarily due to the disposition of non-core oil properties. Natural Gas Production In the first quarter of 2008, 58% of our natural gas production was from the foothills of Alberta and British Columbia, the deep basin of Alberta and the plains of northeast British Columbia and northwest Alberta; the remainder was from the plains throughout Alberta and southwest Saskatchewan. Production of natural gas was down approximately 8% in the first quarter of 2008 compared with the first quarter of 2007. In 2007, management reduced natural gas drilling activity in response to low natural gas prices and pending higher Alberta gas royalties. ----------------------------------------------------------------------------2008 Gross Production Guidance Three months ended Year ended Guidance Mar. 31 Dec. 31 2008 2008 2007 ----------------------------------------------------------------------------Crude oil & NGL (mbbls/day) Light crude oil & NGL 139 - 148 120.5 139 Medium crude oil 28 - 29 26.9 27 Heavy crude oil & bitumen 114 - 124 104.3 107 ---------------------------------------------------------------------------- 281 - 301 251.7 273 Natural gas (mmcf/day) 625 - 655 590.4 623 Total barrels of oil equivalent (mboe/day) 385 - 410 350.1 377 -------------------------------------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------Upstream Revenue Mix Three months ended March 31 Percentage of upstream net revenues 2008 2007 ----------------------------------------------------------------------------Crude oil & NGL Light crude oil & NGL 44 51 Medium crude oil 8 6 Heavy crude oil & bitumen 29 21 ---------------------------------------------------------------------------- 81 78 Natural gas 19 22 ---------------------------------------------------------------------------- 100 100 -------------------------------------------------------------------------------------------------------------------------------------------------------- Unit Operating Costs Operating costs in Western Canada averaged $12.85/boe in the first quarter of 2008 compared with $10.55/boe in the same period in 2007. Extreme cold weather for part of the quarter increased costs for gas well servicing and methanol injection to deal with gas well freeze ups. Increasing operating costs in Western Canada are generally related to the nature of exploitation necessary to manage production from maturing fields and new more extensive but less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, more extensive pipeline systems, crude and water trucking and more extensive natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. In addition, higher levels of industry activity lead naturally to competition for resources and consequential higher service rates and unit costs. Our efforts are focused on managing rising operating costs. We strive to keep our infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure fully utilized. Operating costs at the East Coast offshore operations averaged $5.27/bbl in the first quarter of 2008 compared with $3.03/bbl in the first quarter of 2007. The higher unit operating cost in 2008 was due to lower production combined with higher maintenance costs resulting from the SeaRose FPSO turnaround. Operating costs at the South China Sea offshore operations averaged $4.63/bbl in the first quarter of 2008 compared with $4.28/bbl in the same period in 2007. Unit Depletion, Depreciation and Amortization Depletion, depreciation and amortization ("DD&A") under the full cost method of accounting for oil and gas activities is calculated on a country-by-country basis. The DD&A rate is calculated by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as an equivalent barrel. The resultant dollar per barrel of oil equivalent is assigned to each barrel of oil equivalent that is produced to determine the DD&A expense for the period. Total unit DD&A averaged $12.25/boe in the first quarter of 2008 compared with $11.37/boe in the first quarter of 2007. In Canada, unit DD&A was $12.34/boe, an increase of 9% over the first quarter of 2007. The higher DD&A rate in Canada was primarily due to a larger capital base. Increased capital spending is required in Western Canada for a greater number of wells to maintain production including more extensive field infrastructure. Off the East Coast of Canada large capital investment is required to develop oil reserves. Embedded Derivative During the first quarter of 2008, a $28 million loss was recorded on an embedded derivative related to a drilling rig contract requiring payment in U.S. currency (refer to Note 15 to the Consolidated Financial Statements). The payments are expected to occur over the three-year period from mid-2008. The amount will fluctuate with the U.S./Cdn forward exchange rate until actual contract settlement. ----------------------------------------------------------------------------Netback Analysis Three months ended March 31 2008 2007 ---------------------------------------------------------------------------- $ % (1) $ % (1) Total Crude oil equivalent (per boe) (2) Gross price 69.37 49.67 Royalties 13.19 19 5.63 11 ---------------------------------------------------------------------------- Net sales price 56.18 44.04 Operating costs (3) 10.75 15 8.34 17 ---------------------------------------------------------------------------- Operating netback 45.43 35.70 DD&A 12.25 18 11.37 23 Administration expenses & other (3) 0.96 1 0.33 1 ---------------------------------------------------------------------------- Earnings before income taxes 32.22 47 24.00 48 --------------------------------------------------------------------------------------------------------------------------------------------------------Canada Crude oil equivalent (per boe) (2) Gross price 68.23 48.99 Royalties 12.70 19 5.45 11 ---------------------------------------------------------------------------- Net sales price 55.53 43.54 Operating costs (3) 10.98 16 8.49 17 ---------------------------------------------------------------------------- Operating netback 44.55 35.05 ---------------------------------------------------------------------------- Western Canada Crude oil (per boe) (2) Light crude oil Gross price 78.12 57.00 Royalties 10.20 13 6.20 11 ---------------------------------------------------------------------------- Net sales price 67.92 50.80 Operating costs (3) 16.59 21 11.95 21 ---------------------------------------------------------------------------- Operating netback 51.33 38.85 ---------------------------------------------------------------------------- Medium crude oil Gross price 72.82 46.19 Royalties 13.39 18 7.96 17---------------------------------------------------------------------------- Net sales price 59.43 38.23 Operating costs (3) 14.55 20 13.56 29 ---------------------------------------------------------------------------- Operating netback 44.88 24.67 ---------------------------------------------------------------------------- Heavy crude oil & bitumen Gross price 63.50 37.67 Royalties 8.22 13 4.72 13 ---------------------------------------------------------------------------- Net sales price 55.28 32.95 Operating costs (3) 14.95 24 11.84 31 ---------------------------------------------------------------------------- Operating netback 40.33 21.11 ----------------------------------------------------------------------------Natural gas (per mcfge) (4) Gross price 7.45 7.01 Royalties 1.42 19 1.44 21 ---------------------------------------------------------------------------- Net sales price 6.03 5.57 Operating costs (3) 1.53 21 1.33 19 ---------------------------------------------------------------------------- Operating netback 4.50 4.24 ----------------------------------------------------------------------------East Coast Light crude oil (per boe) (2) Gross price 97.86 66.46 Royalties (5) 23.84 24 2.11 3 ---------------------------------------------------------------------------- Net sales price 74.02 64.35 Operating costs (3) 5.27 5 3.03 5 ---------------------------------------------------------------------------- Operating netback 68.75 61.32 ----------------------------------------------------------------------------International Light crude oil (per boe) (2) Gross price 100.44 68.25 Royalties 26.54 26 10.35 15 ---------------------------------------------------------------------------- Net sales price 73.90 57.90 Operating costs (3) 4.63 5 4.90 7 ---------------------------------------------------------------------------- Operating netback 69.27 53.00 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Percent of gross price. (2) Includes associated co-products converted to boe. (3) Operating costs exclude accretion, which is included in administration expenses & other. (4) Includes associated co-products converted to mcfge. (5) During the third quarter of 2007, White Rose royalties increased to 16% because the project, off the East Coast, achieved payout status for Tier 1 royalties. Upstream Capital Expenditures Our 2008 Upstream Capital expenditure guidance remains unchanged from that reported in our recently filed annual MD&A. ----------------------------------------------------------------------------2008 Capital Expenditure Guidance (1) (millions of dollars) ----------------------------------------------------------------------------Western Canada - oil & gas $ 1,670 - oil sands 300 East Coast Canada 650 International 430 ---------------------------------------------------------------------------- $ 3,050 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Excludes capitalized administrative costs and capitalized interest. The following table summarizes our capital expenditures for the periods presented. ----------------------------------------------------------------------------Capital Expenditures Summary (1) Three months ended March 31 (millions of dollars) 2008 2007 ----------------------------------------------------------------------------Exploration Western Canada $ 206 $ 165 East Coast Canada and Frontier 25 5 International 30 5 ---------------------------------------------------------------------------- 261 175 ----------------------------------------------------------------------------Development Western Canada 469 388 East Coast Canada 68 54 ---------------------------------------------------------------------------- 537 442 ---------------------------------------------------------------------------- $ 798 $ 617 -------------------------------------------------------------------------------------------------------------------------------------------------------- (1) Excludes capitalized costs related to asset retirement obligations incurred during the period. During the first quarter of 2008, capital expenditures were $675 million (84%) in Western Canada, $93 million (12%) off the East Coast of Canada and $30 million (4%) offshore China, Indonesia and other international areas. Western Canada In Western Canada, we invested $595 million on exploration and development on conventional areas, which produce variously light, medium, heavy crude oil or natural gas throughout the Western Canada Sedimentary Basin, $330 million was invested on properties in Alberta, northeast British Columbia and southern Saskatchewan primarily to further develop properties with proved reserves. We drilled 194 net wells in these regions resulting in 104 oil wells and 87 natural gas wells. In the Lloydminster area of Alberta and Saskatchewan, from which the majority of our heavy crude oil is produced, we invested $222 million, again mainly to extend proved properties. Our principal exploration program is conducted along the foothills of Alberta and British Columbia and in the deep basin region of Alberta. In the first quarter of 2008, we invested $43 million drilling in these natural gas prone areas. During the first quarter of 2008, we drilled 15 net exploration wells in the foothills/deep basin regions; 10 were cased as natural gas wells. Oil sands capital expenditures totalled $80 million during the first quarter of 2008. At Tucker, we spent $17 million, at Sunrise $41 million and $22 million at our other oil sands areas, Caribou and Saleski. The following table discloses the number of gross and net exploration and development wells we completed during the quarter ended March 31, 2008 and the same quarter in 2007. Seventy-nine percent of the net exploration wells and 98% of the net development wells we drilled resulted in wells capable of commercial production. ----------------------------------------------------------------------------Western Canada Wells Drilled Three months ended March 31 2008 2007 Gross Net Gross Net ----------------------------------------------------------------------------Exploration Oil 23 23 20 20 Gas 57 49 65 56 Dry 20 19 9 9 ---------------------------------------------------------------------------- 100 91 94 85 ----------------------------------------------------------------------------Development Oil 120 104 138 130 Gas 116 87 168 137 Dry 3 3 10 10 ---------------------------------------------------------------------------- 239 194 316 277 ----------------------------------------------------------------------------Total 339 285 410 362 -------------------------------------------------------------------------------------------------------------------------------------------------------- White Rose Development During the first quarter of 2008, we spent $68 million primarily for SeaRose FPSO tie-back projects and White Rose betterments. East Coast and Northwest Territories Exploration During the first quarter of 2008, we spent $25 million on two exploration wells in the Central Mackenzie Valley and on preliminary planning for our East Coast exploration program. International During the first quarter of 2008, we spent $30 million on exploration drilling in the South China Sea and seismic on the East Bawean II exploration block in the Java Sea. 4.2 Midstream ----------------------------------------------------------------------------Upgrading Net Earnings Summary Three months ended March 31 (millions of dollars, except where indicated) 2008 2007 ----------------------------------------------------------------------------Gross margin $ 171 $ 138 Operating costs 63 58 Other recoveries (1) (1) Depreciation and amortization 6 6 Income taxes 31 24 ----------------------------------------------------------------------------Net earnings $ 72 $ 51 -------------------------------------------------------------------------------------------------------------------------------------------------------- Selected operating data: Upgrader throughput (1) (mbbls/day) 62.8 69.0 Synthetic crude oil sales (mbbls/day) 55.6 57.8 Upgrading differential ($/bbl) $ 28.53 $ 24.11 Unit margin ($/bbl) $ 33.84 $ 26.44 Unit operating cost (2) ($/bbl) $ 10.98 $ 9.30 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Throughput includes diluent returned to the field. (2) Based on throughput. Upgrading Business Environment During the first quarter of 2008, the upgrading differential averaged $28.53/bbl, 18% higher than a year earlier. The differential is equal to Husky Synthetic Blend, which sells at a premium to West Texas Intermediate, less Lloyd Heavy Blend. During the first quarter of 2008, the overall unit margin was 28% higher than a year earlier, in part, due to the addition of low sulphur off-road diesel to the upgrader's product stream. Upgrader throughput was 9% lower in the first quarter of 2008 compared with the same period in 2007 due to temporary operational issues. Unit operating costs increased by 18% in the first quarter of 2008 compared with a year earlier due primarily to higher consumption of steam and higher natural gas prices. ----------------------------------------------------------------------------Infrastructure and Marketing Net Earnings Summary Three months ended March 31 (millions of dollars, except where indicated) 2008 2007 ----------------------------------------------------------------------------Gross margin - pipeline $ 25 $ 26 - other infrastructure and marketing 89 72 ---------------------------------------------------------------------------- 114 98 Other expenses 3 4 Depreciation and amortization 8 7 Income taxes 31 27 ----------------------------------------------------------------------------Net earnings $ 72 $ 60 --------------------------------------------------------------------------------------------------------------------------------------------------------Selected operating data: Aggregate pipeline throughput (mbbls/day) 504 493 -------------------------------------------------------------------------------------------------------------------------------------------------------- Infrastructure and marketing net earnings in the first quarter of 2008 were $72 million compared with $60 million in the first quarter of 2007. Crude oil marketing and cogeneration earnings were also higher during the first quarter of 2008 compared with the first quarter of 2007. Midstream Capital Expenditures Midstream capital expenditures totalled $32 million in the first three months of 2008: $22 million was spent at the Lloydminster upgrader, primarily for contingent consideration and facility reliability projects. The remaining $10 million was spent on the pipeline extension between Lloydminster and Hardisty, Alberta. 4.3 Downstream ----------------------------------------------------------------------------Canadian Refined Products Net Earnings Summary Three months ended March 31 (millions of dollars, except where indicated) 2008 2007 ----------------------------------------------------------------------------Gross margin - fuel sales $ 38 $ 42 - ancillary sales 10 9 - asphalt sales 19 13 ---------------------------------------------------------------------------- 67 64 Operating and other expenses 4 18 Depreciation and amortization 20 16 Income taxes 13 10 ----------------------------------------------------------------------------Net earnings $ 30 $ 20 --------------------------------------------------------------------------------------------------------------------------------------------------------Selected operating data: Number of fuel outlets 501 506 Light oil sales (million litres/day) 7.9 8.9 Light oil retail sales per outlet (thousand litres/day) 13.1 13.1 Prince George refinery throughput (mbbls/day) 11.4 11.1 Asphalt sales (mbbls/day) 17.8 17.3 Lloydminster refinery throughput (mbbls/day) 22.0 24.7 Ethanol production (thousand litres/day) 649.1 318.1 -------------------------------------------------------------------------------------------------------------------------------------------------------- Canadian Refined Products Business Environment The Canadian refined products business segment acquires refined product primarily at rack prices from third party refiners. During the first quarter of 2008 we benefited from higher throughput at the Prince George refinery, which produces a high gasoline yield. Product sales from the Prince George refinery, which accounted for 23% of our total Canadian refined product requirement, provided an offset to first quarter margin declines. During the first quarter of 2008 asphalt product margins were approximately 40% higher than a year earlier. Asphalt sales were primarily from lower cost 2007 inventory. Additional value was captured in the quarter from higher volumes of residuals and distillates produced at the Lloydminster refinery and processed at the Lloydminster upgrader into low sulphur off-road diesel, and synthetic crude oil. First quarter 2008 ethanol margins were down 9% from last year, slightly better than conventional fuel margins. Ethanol is a high octane clean burning blending stock that adds value to low octane gasoline and receives government incentives. Ethanol sales during the first quarter of 2008 were double those in the same period in 2007. The new Minnedosa ethanol plant commenced operation at the end of 2007. ----------------------------------------------------------------------------U.S. Refining and Marketing Net Earnings Summary Three months ended March 31 (millions of dollars, except where indicated) 2008 ----------------------------------------------------------------------------Gross refining margin $ 87 Processing costs 53 Operating and other expenses 1 Interest - net 1 Depreciation and amortization 19 Income taxes 5 ----------------------------------------------------------------------------Net earnings $ 8 --------------------------------------------------------------------------------------------------------------------------------------------------------Selected operating data: Refinery throughput (mbbls/day) Crude oil and other feedstock 138.4 Yield (mbbls/day) Gasoline 74.2 Middle distillates 49.5 Other fuel and feedstock 11.4 Gross refining margin ($/bbl crude throughput) 6.91 Unit operating costs ($/bbl of yield) 4.33 Refined product sales (mbbls/day) Gasoline 86.4 Middle distillates 45.9 Other fuel and feedstock 10.1 -------------------------------------------------------------------------------------------------------------------------------------------------------- The U.S. Refining and Marketing segment commenced operations effective July 1, 2007 with the acquisition of the Lima, Ohio refinery. The Lima refinery has a crude oil throughput capacity of 160 mbbls/day. U.S. Refining and Marketing Business Environment In the downstream sector the drop in demand for motor fuels that began in mid 2007 was more pronounced in the first quarter of 2008 and in line with U.S. economic conditions and the traditional weak first quarter refining margin environment. Lower consumption combined with higher product stocks resulted in narrow refinery crack spreads. The 3:2:1 crack spread is the key proxy for refining margins since, on average, refinery gasoline output is around twice the distillate output. This crack spread is equal to the price of 2/3 barrel of gasoline plus 1/3 barrel of diesel (distillate) less 1 barrel of crude oil. During the first quarter of 2008 the New York Harbour 3:2:1 crack spread averaged U.S. $10.09/bbl, 11% lower than a year earlier. March margins continued to grow with market fundamentals strengthening entering the spring driving season. Downstream Capital Expenditures Refined Products capital expenditures totalled $19 million during the first quarter of 2008. Capital spending was primarily related to various environmental protection and reliability upgrades at our refineries and plants and for marketing location upgrades and construction. 4.4 Corporate ----------------------------------------------------------------------------Corporate Summary Three months ended March 31 (millions of dollars) income (expense) 2008 2007 ----------------------------------------------------------------------------Intersegment eliminations - net $ (9) $ (25) Administration expenses 49 (38) Depreciation and amortization (7) (5) Interest - net (45) (21) Foreign exchange (10) 1 Income taxes 10 27 ----------------------------------------------------------------------------Net earnings (loss) $ (12) $ (61) -------------------------------------------------------------------------------------------------------------------------------------------------------- In the first quarter of 2008, administration expenses reflected a recovery of stock-based compensation expense. The increase in net interest expense during the first quarter of 2008 compared with a year earlier was primarily due to a higher level of debt. Additional debt was issued during 2007 for the acquisition of the Lima refinery. ----------------------------------------------------------------------------Foreign Exchange Summary Three months ended March 31 (millions of dollars) 2008 2007 ----------------------------------------------------------------------------(Gain) loss on translation of U.S. dollar denominated long-term debt Unrealized $ 44 $ (14) ---------------------------------------------------------------------------- 44 (14) Cross currency swaps (14) 4 Other (gains) losses (20) 9 ---------------------------------------------------------------------------- $ 10 $ (1) --------------------------------------------------------------------------------------------------------------------------------------------------------U.S./Canadian dollar exchange rates: At beginning of period U.S. $1.012 U.S. $0.858 At end of period U.S. $0.973 U.S. $0.867 -------------------------------------------------------------------------------------------------------------------------------------------------------- Corporate Capital Expenditures Corporate capital expenditures totaled $12 million in the first three months of 2008 primarily for various office and information system upgrades. Consolidated Income Taxes During the first quarter of 2008, consolidated income taxes consisted of $225 million of current taxes and $154 million of future taxes compared with current taxes of $72 million and future taxes of $225 million in the same period of 2007. The increase in current taxes and decrease in future taxes in the first quarter of 2008 compared with the first quarter of 2007 was due to the deferral of White Rose income. 4.5 Sensitivity Analysis The following table indicates the relative annual effect of changes in certain key variables on our pre-tax cash flow and net earnings. The analysis is based on business conditions and production volumes during the first quarter of 2008. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change. Sensitivity Analysis 2008 First Quarter Average Increase ---------------------------------------------------------------------------- Upstream and Midstream WTI benchmark crude oil price $ 97.90 U.S. $1.00/bbl NYMEX benchmark natural gas price (1) $ 8.03 U.S. $0.20/mmbtu WTI/Lloyd crude blend differential (2) $ 21.81 U.S. $1.00/bbl Downstream Light oil margins $ 0.04 Cdn $0.005/litre Asphalt margins $ 10.99 Cdn $1.00/bbl New York Harbor 3:2:1 crack spread (3) $ 10.09 U.S. $1.00/bbl Consolidated Exchange rate (U.S. $ per Cdn $) (4) $ 0.996 U.S. $0.01 Interest rate 1% Period end translation of U.S. $ debt (U.S. $ per Cdn $) $ 0.973 (5) U.S. $0.01 -------------------------------------------------------------------------------------------------------------------------------------------------------- Sensitivity Analysis Effect on Pre-tax Effect on Cash Flow (6) Net Earnings (6) ---------------------------------------------------------------------------- ($ millions) ($/share) (7) ($ millions) ($/share) (7) Upstream and Midstream WTI benchmark crude oil price 74 0.09 52 0.06 NYMEX benchmark natural gas price (1) 25 0.03 17 0.02 WTI/Lloyd crude blend differential (2) (28) (0.03) (19) (0.02) Downstream Light oil margins 14 0.02 9 0.01 Asphalt margins 7 0.01 4 - New York Harbor 3:2:1 crack spread (3) 48 0.06 30 0.04 Consolidated Exchange rate (U.S. $ per Cdn $) (4) (76) (0.09) (55) (0.06) Interest rate (10) (0.01) (7) (0.01) Period end translation of U.S. $ debt (U.S. $ per Cdn $) 20 0.02 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Includes decrease in net earnings related to natural gas consumption. (2) Includes impact of upstream and upgrading operations only. (3) Relates to the Lima, Ohio refinery. (4) Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items. (5) U.S./Canadian dollar exchange rate at March 31, 2008. (6) Excludes derivatives. (7) Based on 849.0 million common shares outstanding as of March 31, 2008. 5. Liquidity and Capital Resources During the first quarter of 2008, cash flow from operating activities financed all of our capital requirements and dividend payment. At March 31, 2008 we had $1.4 billion in unused committed credit facilities. ----------------------------------------------------------------------------Cash Flow Summary Three months ended March 31 (millions of dollars, except ratios) 2008 2007 ----------------------------------------------------------------------------Cash flow - operating activities $ 1,227 $ 672 - financing activities $ (101) $ (222) - investing activities $ (968) $ (892) Financial Ratios Debt to capital employed (percent) 19.7 14.1 Corporate reinvestment ratio (percent) (1) (2) 58 63 --------------------------------------------------------------------------------------------------------------------------------------------------------(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 first quarter of 2008, cash generated from operating activities amounted to $1.2 billion compared with $672 million in the first quarter of 2007. 5.2 Financing Activities In the first quarter of 2008, cash used in financing activities was $101 million compared with $222 million in the first quarter of 2007. During the first quarter of 2008, cash provided by a change in non-cash working capital associated with financing activities and lower dividends primarily resulted in a lower use of cash compared with the first quarter of 2007. The change in non-cash working capital mainly related to a decrease in dividends payable due to the special dividend of $0.25 per common share declared in February 2007. 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 first quarter of 2008, cash used in investing activities amounted to $968 million compared with $892 million in the first quarter of 2007. Cash invested in both periods was used primarily for capital expenditures. 5.4 Sources of Capital We are currently able to fund our capital programs principally by cash provided from operating activities. We also maintain access to sufficient capital via capital debt markets commensurate with the strength of our balance sheet and continually examine our options with respect to sources of long and short-term capital resources. In addition, from time to time we engage in hedging a portion of our revenue to protect cash flow. Working capital is the amount by which current assets exceed current liabilities. At March 31, 2008, our working capital was $595 million compared with a working capital deficiency of $51 million at December 31, 2007. The increase in working capital was related to feedstock and refined product inventories and higher accounts receivable at our U.S. refining operations and higher accounts receivable for our Canadian crude oil production. The higher working capital from accounts receivable and inventories was partially offset by higher accounts payable primarily for U.S. refinery feedstock purchases. ---------------------------------------------------------------------------- March 31 Dec. 31 (millions of dollars) 2008 2007 Change ----------------------------------------------------------------------------Current assets Cash and cash equivalents $ 366 $ 208 $ 158 Accounts receivable 1,957 1,622 335 Higher crude oil prices Inventories 1,651 1,190 461 Inclusion of Toledo inventory; increased Lima inventory Prepaid expenses 27 28 (1) -------------------------------------------------- 4,001 3,048 953 Current liabilities Bank operating loans 77 - (77) Accounts payable 1,629 1,460 (169) Higher crude oil prices and higher royalties Accrued interest payable 29 20 (9) Income taxes payable 112 36 (76) Timing of tax payments Other accrued liabilities 788 842 54 Long-term debt due within Foreign exchange impact one year 771 741 (30) on U.S. dollar -------------------------------------------------- denominated debt 3,406 3,099 (307) --------------------------------------------------Working capital $ 595 $ (51) $ 646 -------------------------------------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------Capital Structure March 31, 2008 (millions of dollars) Outstanding Available ----------------------------------------------------------------------------Total short-term and long-term debt $ 3,096 $ 1,422 Common shares, retained earnings and accumulated other comprehensive income $ 12,300 -------------------------------------------------------------------------------------------------------------------------------------------------------- At March 31, 2008, we had unused committed long and short-term borrowing credit facilities totalling $1.4 billion. A total of $71 million of our borrowing credit facilities were used in support of outstanding letters of credit and an additional $21 million of letters of credit were outstanding at March 31, 2008 supported by dedicated letters of credit lines. The Sunrise Oil Sands Partnership has an unsecured demand credit facility available of $10 million for general purposes. The Company's proportionate share is $5 million. We currently have a shelf prospectus dated September 21, 2006 that enabled us to offer up to U.S. $1.0 billion of debt securities in the United States until October 21, 2008. During the 25 months that the prospectus is effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale. As of the date of this Management's Discussion and Analysis, U.S. $750 million of debt securities had been issued under this shelf prospectus and the remaining amount of U.S. $250 million is eligible for issue. 5.5 Credit Ratings On March 31, 2008, DBRS upgraded our Senior Unsecured Notes and Debentures to A (low) and our Capital Securities to BBB (high) both with stable trends. Our other credit ratings are available in our recently filed Annual Information Form at www.sedar.com. 5.6 Contractual Obligations and Commercial Commitments Refer to Husky's 2007 annual Management's Discussion and Analysis under the caption "Cash Requirements," which summarizes contractual obligations and commercial commitments as at December 31, 2007. At March 31, 2008, we had additional contractual obligations to purchase goods and services totalling $1,150 million. These contracts are expected to be settled in the following periods: 2008 - $687 million; 2009 - $331 million; and 2010 - $132 million. Our East Coast exploration and development program accounts for 62% of the total value of these additional contracts and the remaining amounts are for refined petroleum product purchases. 5.7 Off Balance Sheet Arrangements We do not utilize off balance sheet arrangements with unconsolidated entities to enhance perceived liquidity. We engage, in the ordinary course of business, in the securitization of accounts receivable. At March 31, 2008, 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. 5.8 Transactions with Related Parties TransAlta Power, L.P. is an indirect subsidiary of Cheung Kong Infrastructure Holdings Ltd., which is majority owned by Hutchison Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd., a 34.58% shareholder in Husky. TransAlta Power, L.P. is a 49.99% owner of TransAlta Cogeneration, L.P., our partner in the Meridian cogeneration plant in Lloydminster, Saskatchewan. We sell natural gas to the Meridian cogeneration plant and other cogeneration plants owned by TransAlta Power, L.P. During the first quarter of 2008, we sold $31 million of natural gas to TransAlta Power, L.P. 6. Risk Management Husky is exposed to market risks and various operational risks. For a detailed discussion of these risks see our Annual Information Form recently filed on the Canadian Securities Administrator's web site, www.sedar.com, the Securities Exchange Commission's web site, www.sec.gov or our web site Our financial risks are largely related to commodity prices, exchange rates, interest rates, credit risk, changes in fiscal policy related to royalties and taxes and others. From time to time, we use financial and derivative instruments to manage our exposure to these risks. Interest Rate Risk Management In the first three months of 2008, interest rate risk management activities resulted in a decrease to interest expense of less than $1 million. Husky has interest rate swaps on $200 million of long-term debt effective February 8, 2002 whereby 6.95% was swapped for CDOR + 175 bps until July 14, 2009. During the first three months of 2008, these swaps resulted in an offset to interest expense amounting to $1 million. The amortization of previous interest rate swap terminations resulted in an additional $1 million offset to interest expense in the first three months of 2008. Cross currency swaps resulted in an addition to interest expense of $2 million in the first three months of 2008. Foreign Currency Risk Management At March 31, 2008, we had the following cross currency debt swaps in place: - U.S. $150 million at 6.25% swapped at $1.41 to $212 million at 7.41% until June 15, 2012. - U.S. $75 million at 6.25% swapped at $1.19 to $90 million at 5.65% until June 15, 2012. - U.S. $50 million at 6.25% swapped at $1.17 to $59 million at 5.67% until June 15, 2012. - U.S. $75 million at 6.25% swapped at $1.17 to $88 million at 5.61% until June 15, 2012. At March 31, 2008, we had the following freestanding derivatives in place where Husky had entered into forward purchases of U.S. dollars to partially offset exposure on an embedded derivative (refer to Note 15 to the Consolidated Financial Statements): - U.S. $119 million bought at $0.9854 for $117 million from January 2008 to June 2011. - U.S. $119 million bought at $0.9772 for $116 million from January 2008 to June 2011. - U.S. $119 million bought at $0.9670 for $115 million from January 2008 to June 2011. At March 31, 2008 the cost of a U.S. dollar in Canadian currency was $1.0279. Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky's U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At March 31, 2008, 90% or $2.7 billion of our long-term debt was denominated in U.S. dollars. The percentage of our long-term debt exposed to the Cdn/U.S. exchange rate decreases to 78% when cross currency swaps are considered. Effective July 1, 2007, the Company's U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the Company's net investment in the U.S. refining operations, which are considered self-sustaining. As at March 31, 2008, unrealized foreign exchange loss arising from the translation of the debt was $51 million, net of tax of $9 million which was recorded in "Other Comprehensive Income." 7. Critical Accounting Estimates Certain of our accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. For a discussion about those accounting policies, please refer to our Management's Discussion and Analysis for the year ended December 31, 2007 available at www.sedar.com. 8. Changes in Accounting Policies Inventories Effective January 1, 2008, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3031, "Inventories," which replaced CICA section 3030 of the same name. The new guidance provides additional measurement and disclosure requirements and requires the Company to reverse previous impairment write-downs when there is a change in the situation that caused the impairment. The transitional provisions of section 3031 provided entities with the option of applying this guidance retrospectively and restating prior periods in accordance with section 1506, "Accounting Changes" or adjusting opening retained earnings and not restating prior periods. The adoption of this standard did not have an impact on the Company's financial statements. Financial Instruments - Disclosure and Presentation Effective January 1, 2008, the Company adopted CICA section 3862, "Financial Instruments - Disclosures" and CICA section 3863, "Financial Instruments - Presentation," which replaced CICA section 3861, "Financial Instruments - Disclosure and Presentation." Section 3862 outlines the disclosure requirements for financial instruments and non-financial derivatives. This guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, section 3862 requires disclosure of the significance of financial instruments on the Company's financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. The presentation requirements under section 3863 are relatively unchanged from section 3861. Refer to Note 15 to the Consolidated Financial Statements for the additional disclosures under section 3862. Capital Disclosures Effective January 1, 2008, the Company adopted CICA section 1535, "Capital Disclosures." This new guidance requires disclosure about the Company's objectives, policies and processes for managing capital. These disclosures include a description of what the Company manages as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into the Company's management of capital, whether the requirements have been complied with, or consequence of non-compliance and an explanation of how the Company is meeting its objectives for managing capital. In addition, quantitative disclosures regarding capital are required. Refer to Note 16 to the Consolidated Financial Statements. 9. Outstanding Share Data ---------------------------------------------------------------------------- March 31 December 31 (in thousands) 2008 2007 ----------------------------------------------------------------------------Issued and outstanding at end of period (1) Number of common shares 849,044 848,960 Number of stock options 31,086 30,131 Number of stock options exercisable 3,887 4,494 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) 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 March 31, 2008 to April 11, 2008. During this period, 7 thousand stock options were exercised for shares and 24 thousand stock options were surrendered for cash. At April 11, 2008, the Company had 849,051 thousand common shares outstanding and there were 31,055 thousand stock options outstanding, of which 3,856 thousand were exercisable. 10. Reader Advisories This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. Readers are encouraged to refer to Husky's MD&A and Consolidated Financial Statements and 2007 Annual Information Form filed in 2008 with Canadian regulatory agencies and Form 40-F filed with the Securities and Exchange Commission, the U.S. regulatory agency. These documents are available at www.sedar.com, at 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 March 31, 2008 are compared with results for the three months ended March 31, 2007. Discussions with respect to Husky's financial position as at March 31, 2008 are compared with its financial position at December 31, 2007. Additional Reader Guidance - The Consolidated Financial Statements and comparative financial information included in this Interim Report have been prepared in accordance with Canadian 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. 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: ---------------------------------------------------------------------------- Three months ended March 31 (millions of dollars) 2008 2007 ----------------------------------------------------------------------------Non-GAAP Cash flow from operations $ 1,541 $ 1,324 Settlement of asset retirement obligations (17) (14) Change in non-cash working capital (297) (638) ----------------------------------------------------------------------------GAAP Cash flow - operating activities $ 1,227 $ 672 -------------------------------------------------------------------------------------------------------------------------------------------------------- Cautionary Note Required by National Instrument 51-101 The Company uses the terms barrels of oil equivalent ("boe") and thousand cubic feet of gas equivalent ("mcfge"), which are calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the terms boe and mcfge may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the wellhead. Husky's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Husky by Canadian securities regulatory authorities, which permits Husky to provide disclosure required by and consistent with the requirements of the United States Securities and Exchange Commission and the Financial Accounting Standards Board in the United States in place of much of the disclosure expected by National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer to "Disclosure of Exemption Under National Instrument 51-101" on page 2 of our Annual Information Form for the year ended December 31, 2007 filed with securities regulatory authorities for further information. Abbreviations bbls barrels bps basis points mbbls thousand barrels mbbls/day thousand barrels per day mmbbls million barrels mcf thousand cubic feet mmcf million cubic feet mmcf/day million cubic feet per day bcf billion cubic feet tcf trillion cubic feet boe barrels of oil equivalent mboe thousand barrels of oil equivalent mboe/day thousand barrels of oil equivalent per day mmboe million barrels of oil equivalent mcfge thousand cubic feet of gas equivalent GJ gigajoule mmbtu million British Thermal Units mmlt million long tons NGL natural gas liquids WTI West Texas Intermediate NYMEX New York Mercantile Exchange NIT NOVA Inventory Transfer LIBOR London Interbank Offered Rate CDOR Certificate of Deposit Offered Rate SEDAR System for Electronic Document Analysis and Retrieval FPSO Floating production, storage and offloading vessel FEED Front-end engineering design Terms Bitumen A naturally occurring viscous mixture consisting mainly of pentanes and heavier hydrocarbons. It is more viscous than 10 degrees API Capital Employed Short- and long-term debt and shareholders' equity Capital Expenditures Includes capitalized administrative expenses and capitalized interest but does not include proceeds or other assets Capital Program Capital expenditures not including capitalized administrative expenses or capitalized interest Cash Flow from Operations Earnings from operations plus non-cash charges before settlement of asset retirement obligations and change in non-cash working capital Corporate Reinvestment Ratio Net capital expenditures (capital expenditures net of proceeds from asset sales) plus corporate acquisitions (net assets acquired) divided by cash flow from operations Dated Brent Prices which are dated less than 15 days prior to loading for delivery Debt to Capital Employed Total debt divided by total debt and shareholders' equity Delineation Well A well in close proximity to an oil or gas discovery well that helps determine the areal extent of the reservoir Diluent A lighter gravity liquid hydrocarbon, usually condensate or synthetic oil, added to heavy oil to facilitate transmissibility through a pipeline Embedded Derivative Implicit or explicit term(s) in a contract that affects some or all of the cash flows or the value of other exchanges required by the contract Equity Shares, retained earnings and accumulated other comprehensive income Feedstock Raw materials which are processed into petroleum products Front-end Engineering Design Preliminary engineering and design planning, which among other things, identifies project objectives, scope, alternatives, specifications, risks, costs, schedule and economics Glory Hole An excavation in the seabed where the wellheads and other equipment are situated to protect them from scouring icebergs Gross/Net Acres/Wells Gross refers to the total number of acres/ wells in which an interest is owned. Net refers to the sum of the fractional working interests owned by a company Gross Reserves/Production A company's working interest share of reserves/production before deduction of royalties Hectare One hectare is equal to 2.47 acres Near-month Prices Prices quoted for contracts for settlement during the next month NOVA Inventory Transfer Exchange or transfer of title of gas that has been received into the NOVA pipeline system but not yet delivered to a connecting pipeline Return on Capital Employed Net earnings plus after tax interest expense divided by average capital employed Return on Shareholders' Equity Net earnings divided by average shareholders' equity Stratigraphic Well A geologically directed test well to obtain information. These wells are usually drilled without the intention of being completed for production Synthetic Oil A mixture of hydrocarbons derived by upgrading heavy crude oils, including bitumen, through a process that reduces the carbon content and increases the hydrogen content Three Dimensional (3-D) Seismic Seismic imaging which uses a grid of numerous cables rather than a few lines stretched in one line Total Debt Long-term debt including current portion and bank operating loans Turnaround Scheduled performance of plant or facility maintenance Forward-Looking Statements or Information Certain statements in this release and Interim Report are forward-looking statements or information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company's actual results to differ materially from those projected in these forward-looking statements. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "intend," "plan," "projection," "could," "vision," "goals," "objective" and "outlook") are not historical facts and are forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include, but are not limited to: our 2008 production and capital spending guidance, our annualized sensitivity analysis of the effect of changes in key variables on our pre-tax cash flow and net earnings, our East Coast exploration and White Rose delineation and SeaRose FPSO tie-back plans, our development plans for the North Amethyst oil field, our production optimization plans for the Tucker in-situ oil sands project, our Sunrise phased development plans, our Caribou and Saleski oil sands projects plans and development application schedule, our Northwest Territories exploration program, the schedule and results of our offshore China geophysical and drilling programs, the Liwan natural gas discovery delineation and development plans, the receipt of approvals for and commencement of production at the Madura BD natural gas and NGL field, the results of our seismic data analysis from the East Bawean II exploration block in the East Java Sea, our work programs for offshore Greenland and our plans to review options in respect of reconfiguring and expanding the Lima refinery and our plans to modify the Toledo refinery. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this release. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar. Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to: - the prices we receive for our crude and natural gas production; - demand for our products and our cost of operations; - our ability to replace our proved oil and gas reserves in a cost-effective manner; - competitive actions of other companies, including increased competition from other oil and gas companies; - business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable; - foreign exchange risk; - actions by governmental authorities, including changes in environmental and other regulations that may impose operating costs or restrictions in areas where we operate; and - the accuracy of our reserve estimates and estimated production levels. These risks, uncertainties and other factors are discussed in our Annual Information Form and our Form 40-F, available at www.sedar.com and www.sec.gov, respectively. Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable law, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. CONSOLIDATED FINANCIAL STATEMENTS Consolidated Balance Sheets ---------------------------------------------------------------------------- March 31 December 31 (millions of dollars, except share data) 2008 2007 ---------------------------------------------------------------------------- (unaudited) Assets Current assets Cash and cash equivalents $ 366 $ 208 Accounts receivable 1,957 1,622 Inventories 1,651 1,190 Prepaid expenses 27 28 ---------------------------------------------------------------------------- 4,001 3,048 Property, plant and equipment 30,417 29,407 Less accumulated depletion, depreciation and amortization 12,055 11,602 ---------------------------------------------------------------------------- 18,362 17,805 Goodwill 680 660 Contribution receivable (note 6) 1,177 -Other assets 171 184 ---------------------------------------------------------------------------- $ 24,391 $ 21,697 --------------------------------------------------------------------------------------------------------------------------------------------------------Liabilities and Shareholders' Equity Current liabilities Bank operating loans (note 8) $ 77 $ - Accounts payable and accrued liabilities 2,558 2,358 Long-term debt due within one year (note 9) 771 741 ---------------------------------------------------------------------------- 3,406 3,099 Long-term debt (note 9) 2,248 2,073 Contribution payable (note 6) 1,290 -Other long-term liabilities (note 10) 912 918 Future income taxes 4,235 3,957 Commitments and contingencies (note 11) Shareholders' equity Common shares (note 12) 3,555 3,551 Retained earnings 8,783 8,176 Accumulated other comprehensive income (38) (77) ---------------------------------------------------------------------------- 12,300 11,650 ---------------------------------------------------------------------------- $ 24,391 $ 21,697 --------------------------------------------------------------------------------------------------------------------------------------------------------Common shares outstanding (millions) (note 12) 849.0 849.0 --------------------------------------------------------------------------------------------------------------------------------------------------------The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated Statements of Earnings and Comprehensive Income ---------------------------------------------------------------------------- Three months ended March 31 (millions of dollars, except share data) (unaudited) 2008 2007 ----------------------------------------------------------------------------Sales and operating revenues, net of royalties $ 5,086 $ 3,244 Costs and expenses Cost of sales and operating expenses 3,307 1,779 Selling and administration expenses 51 38 Stock-based compensation (43) 21 Depletion, depreciation and amortization 450 433 Interest - net (note 9) 46 21 Foreign exchange (note 9) 10 (1) Other - net (1) 6 ---------------------------------------------------------------------------- 3,820 2,297 ----------------------------------------------------------------------------Earnings before income taxes 1,266 947 ----------------------------------------------------------------------------Income taxes Current 225 72 Future 154 225 ---------------------------------------------------------------------------- 379 297 ----------------------------------------------------------------------------Net earnings 887 650 Other comprehensive income Derivatives designated as cash flow hedges, net of tax (2) 2 Cumulative foreign currency translation adjustment 92 - Hedge of net investment, net of tax (51) -----------------------------------------------------------------------------Comprehensive income $ 926 $ 652 --------------------------------------------------------------------------------------------------------------------------------------------------------Earnings per share Basic and diluted $ 1.04 $ 0.77 Weighted average number of common shares outstanding (millions) Basic and diluted 849.0 848.6 --------------------------------------------------------------------------------------------------------------------------------------------------------The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated Statements of Changes in Shareholders' Equity ---------------------------------------------------------------------------- Three months ended March 31 (millions of dollars) (unaudited) 2008 2007 ----------------------------------------------------------------------------Common shares Beginning of period $ 3,551 $ 3,533 Options exercised 4 3 ---------------------------------------------------------------------------- End of period 3,555 3,536 ----------------------------------------------------------------------------Retained earnings Beginning of period 8,176 6,087 Net earnings 887 650 Dividends on common shares Ordinary (280) (212) Special - (212) Adoption of financial instruments - 4 ---------------------------------------------------------------------------- End of period 8,783 6,317 ----------------------------------------------------------------------------Accumulated other comprehensive income Beginning of period (77) - Adoption of financial instruments - (18) Other comprehensive income Derivatives designated as cash flow hedges, net of tax (2) 2 Cumulative foreign currency translation adjustment 92 - Hedge of net investment, net of tax (51) ----------------------------------------------------------------------------- 39 2 ---------------------------------------------------------------------------- End of period (38) (16) ----------------------------------------------------------------------------Shareholders' equity $ 12,300 $ 9,837 --------------------------------------------------------------------------------------------------------------------------------------------------------The accompanying notes to the consolidated financial statements are an integral part of these statements. Consolidated Statements of Cash Flows ---------------------------------------------------------------------------- Three months ended March 31 (millions of dollars) (unaudited) 2008 2007 ----------------------------------------------------------------------------Operating activities Net earnings $ 887 $ 650 Items not affecting cash Accretion (note 10) 13 12 Depletion, depreciation and amortization 450 433 Future income taxes 154 225 Foreign exchange 31 (10) Other 6 14 Settlement of asset retirement obligations (note 10) (17) (14) Change in non-cash working capital (note 7) (297) (638) ---------------------------------------------------------------------------- Cash flow - operating activities 1,227 672 ----------------------------------------------------------------------------Financing activities Bank operating loans financing - net 77 83 Long-term debt issue 375 435 Long-term debt repayment (275) (535) Proceeds from exercise of stock options 1 1 Dividends on common shares (280) (424) Other (8) - Change in non-cash working capital (note 7) 9 218 ---------------------------------------------------------------------------- Cash flow - financing activities (101) (222) ----------------------------------------------------------------------------Available for investing 1,126 450 ----------------------------------------------------------------------------Investing activities Capital expenditures (852) (734) Asset sales 30 - Other 19 (2) Change in non-cash working capital (note 7) (165) (156) ---------------------------------------------------------------------------- Cash flow - investing activities (968) (892) ----------------------------------------------------------------------------Increase (decrease) in cash and cash equivalents 158 (442) Cash and cash equivalents, beginning of period 208 442 ----------------------------------------------------------------------------Cash and cash equivalents, end of period $ 366 $ ---------------------------------------------------------------------------------------------------------------------------------------------------------The accompanying notes to the consolidated financial statements are an integral part of these statements. Notes to the Consolidated Financial Statements Three months ended March 31, 2008 (unaudited) Except where indicated, all dollar amounts are in millions. Note 1 Segmented Financial Information ---------------------------------------------------------------------------- Upstream Midstream Infrastructure and Upgrading Marketing 2008 2007 2008 2007 2008 2007 --------------------------------------------------------------------------------------------------------------------------------------------------------Three months ended March 31 Sales and operating revenues, net of royalties $ 1,829 $ 1,565 $ 483 $ 359 $3,102 $2,555 Costs and expenses Operating, cost of sales, selling and general 413 323 374 278 2,991 2,461 Depletion, depreciation and amortization 390 399 6 6 8 7 Interest - net - - - - - - Foreign exchange - - - - - ----------------------------------------------------------------------------- 803 722 380 284 2,999 2,468 ----------------------------------------------------------------------------Earnings (loss) before income taxes 1,026 843 103 75 103 87 Current income taxes 166 22 22 1 30 16 Future income taxes 143 241 9 23 1 11 ----------------------------------------------------------------------------Net earnings (loss) $ 717 $ 580 $ 72 $ 51 $ 72 $ 60 --------------------------------------------------------------------------------------------------------------------------------------------------------Capital expenditures - Three months ended March 31 $ 798 $ 617 $ 22 $ 48 $ 10 $ 36 Goodwill additions - Three months ended March 31 $ - $ - $ - $ - $ - $ -Total assets - As at March 31 $13,114 $14,168 $1,434 $1,177 $1,322 $1,057 -------------------------------------------------------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------- Corporate and Downstream Eliminations (1) Total U.S. Canadian Refining Refined and Products Marketing 2008 2007 2008 2007 2008 2007 2008 2007 --------------------------------------------------------------------------------------------------------------------------------------------------------Three months ended March 31 Sales and operating revenues, net of royalties $ 722 $ 618 $1,329 $ - $(2,379) $(1,853) $ 5,086 $ 3,244 Costs and expenses Operating, cost of sales, selling and general 659 572 1,296 - (2,419) (1,790) 3,314 1,844 Depletion, depreciation and amortization 20 16 19 - 7 5 450 433 Interest - net - - 1 - 45 21 46 21 Foreign exchange - - - - 10 (1) 10 (1) ---------------------------------------------------------------------------- 679 588 1,316 - (2,357) (1,765) 3,820 2,297 ----------------------------------------------------------------------------Earnings (loss) before income taxes 43 30 13 - (22) (88) 1,266 947 Current income taxes 6 8 (22) - 23 25 225 72 Future income taxes 7 2 27 - (33) (52) 154 225 ----------------------------------------------------------------------------Net earnings (loss) $ 30 $ 20 $ 8 $ - $ (12) $ (61) $ 887 $ 650 --------------------------------------------------------------------------------------------------------------------------------------------------------Capital expenditures - Three months ended March 31 $ 19 $ 40 $ 7 $ - $ 12 $ 5 $ 868 $ 746 Goodwill additions - Three months ended March 31 $ - $ - $ - $ - $ - $ - $ - $ -Total assets - As at March 31 $1,396 $1,180 $6,574 $ - $ 551 $ 199 $24,391 $17,781 --------------------------------------------------------------------------------------------------------------------------------------------------------(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. Geographical Financial Information ---------------------------------------------------------------------------- United Other Canada States International Total 2008 2007 2008 2007 2008 2007 2008 2007 --------------------------------------------------------------------------------------------------------------------------------------------------------Three months ended March 31 Sales and operating revenues, net of royalties $ 3,384 $ 2,836 $1,618 $336 $ 84 $ 72 $ 5,086 $ 3,244 Capital expenditures (1) 831 741 7 - 30 5 868 746 As at March 31 Property, plant and equipment, net $16,511 $15,513 $1,460 $ 3 $391 $341 $18,362 $15,857 Goodwill (2) 160 160 520 - - - 680 160 --------------------------------------------------------------------------------------------------------------------------------------------------------(1) Excludes capitalized costs related to asset retirement obligations incurred during the period and corporate acquisitions. (2) Changes in goodwill for the U.S. arise from translation of goodwill in our self-sustaining U.S. operations. Note 2 Significant Accounting Policies The interim consolidated financial statements of Husky Energy Inc. ("Husky" or "the Company") have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the fiscal year ended December 31, 2007, except as noted below. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in the Company's annual report for the year ended December 31, 2007. Certain prior years' amounts have been reclassified to conform with current presentation. Note 3 Changes in Accounting Policies Inventories Effective January 1, 2008, the Company adopted the Canadian Institute of Chartered Accountants ("CICA") section 3031, "Inventories," which replaced CICA section 3030 of the same name. The new guidance provides additional measurement and disclosure requirements and requires the Company to reverse previous impairment write-downs when there is a change in the situation that caused the impairment. The transitional provisions of section 3031 provided entities with the option of applying this guidance retrospectively and restating prior periods in accordance with section 1506, "Accounting Changes" or adjusting opening retained earnings and not restating prior periods. The adoption of this standard did not have an impact on the Company's financial statements. Note 4 New Disclosures a) Financial Instruments - Disclosure and Presentation Effective January 1, 2008, the Company adopted CICA section 3862, "Financial Instruments - Disclosures" and CICA section 3863, "Financial Instruments - Presentation," which replaced CICA section 3861, "Financial Instruments - Disclosure and Presentation." Section 3862 outlines the disclosure requirements for financial instruments and non-financial derivatives. This guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, section 3862 requires disclosure of the significance of financial instruments on the Company's financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. The presentation requirements under section 3863 are relatively unchanged from section 3861. Refer to Note 15, "Financial Instruments and Risk Management" for the additional disclosures under section 3862. b) Capital Disclosures Effective January 1, 2008, the Company adopted CICA section 1535, "Capital Disclosures." This new guidance requires disclosure about the Company's objectives, policies and processes for managing capital. These disclosures include a description of what the Company manages as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into the Company's management of capital, whether the requirements have been complied with, or consequence of non-compliance and an explanation of how the Company is meeting its objectives for managing capital. In addition, quantitative disclosures regarding capital are required. Refer to Note 16, "Capital Disclosures." Note 5 Pending Accounting Pronouncements Goodwill and Intangible Assets In February 2008, the CICA issued CICA section 3064, "Goodwill and Intangible Assets," which will replace CICA section 3062 of the same name. As a result of issuing this guidance, CICA section 3450, "Research and Development Costs," and Emerging Issues Committee Abstract No. 27, "Revenues and Expenditures during the Pre-Operating Period" will be withdrawn. This new guidance reinforces a principles-based approach to the recognition of costs as assets in accordance with the definition of an asset and the criteria for asset recognition under CICA section 1000, "Financial Statement Concepts." Moreover, section 3064 clarifies the application of the concept of matching revenues and expenses in section 1000 to eliminate the current practice of recognizing as assets items that do not meet the definition and recognition criteria. Under this new guidance, fewer items meet the criteria for capitalization. Section 3064 is effective for Husky on January 1, 2009. Intangible assets recognized prior to January 1, 2009 that do not meet the recognition or measurement criteria as outlined in section 3064 are accounted for in accordance with CICA section 1506, "Accounting Changes." An intangible item that was originally recognized as an expense is not recognized as part of the cost of an intangible asset upon transition to section 3064. The Company is currently determining the impact of this standard. Note 6 Joint Venture with BP On March 31, 2008, the Company completed a transaction with BP, which resulted in the formation of a 50/50 joint venture upstream entity and a 50/50 joint venture downstream entity. The upstream entity is a partnership to which Husky has contributed the Sunrise oil sands assets with a fair value of U.S. $2.5 billion as at January 1, 2008 plus capital expenditures for the three-month period ended March 31, 2008 of $41 million. BP's contribution was U.S. $250 million cash and a contribution receivable for the balance of U.S. $2.25 billion and $41 million. The contribution receivable accretes at a rate of 6% and is payable between March 31, 2008 and December 31, 2015 with the final balance due and payable by December 31, 2015. The upstream entity is included as part of the Upstream segment. The downstream entity is a limited liability company to which BP has contributed the Toledo refinery with a fair value of U.S. $2.5 billion, plus capital expenditures for the three-month period ended March 31, 2008 of U.S. $12 million and inventories of U.S. $372 million, less inventory related payables of U.S. $109 million and adjusted earnings of U.S. $14 million. Husky's contribution was U.S. $250 million cash and a contribution payable for the balance of U.S. $2.5 billion. The contribution |