CALGARY, ALBERTA -- 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
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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
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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
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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
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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)
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Net earnings $ 887 $ 1,074 $ 769 $ 721
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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 17,969
Total 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
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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
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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)
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Net earnings $ 650 $ 542 $ 682 $ 978
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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
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(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
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Upstream Net Earnings Summary Three months
ended March 31
(millions of dollars) 2008 2007
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Gross revenues $ 2,253 $ 1,763
Royalties 424 198
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Net revenues 1,829 1,565
Operating and administration expenses 384 323
Depletion, depreciation and amortization 390 399
Other 29 -
Income taxes 309 263
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Net earnings $ 717 $ 580
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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.
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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
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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
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(1) Prices quoted are near-month contract prices for settlement during the
next month.
(2) Dated Brent prices which are dated less than 15 days prior to loading
for delivery.
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 $105.42/bbl. From December 2007 to March 2008 our monthly average heavy oil prices increased by approximately 52%.
Natural Gas
The following graph illustrates the relative changes over several quarters in our natural gas price realized compared with two major benchmark prices.
NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices
Natural gas prices quoted on the NYMEX rose through the first quarter of 2008 and were, on average, 19% higher than the same period in 2007. Higher prices in the first quarter of 2008 are largely attributed to colder weather compared with last winter in the major natural gas consumption regions. At the end of the first quarter of 2008 natural gas stocks in underground storage in the United States were 20% lower than at the same date in 2007.
The average prices realized during the first quarter of 2008 compared with the first quarter of 2007 are illustrated below.
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Average Sales Prices Three months
ended March 31
2008 2007
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Crude Oil ($/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
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Oil and Gas Production
The following table shows our gross daily production rate by location and
product type for five sequential quarters.
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Daily Gross Production
Three months ended
March 31 Dec. 31 Sept. 30 June 30 March 31
2008 2007 2007 2007 2007
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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
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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
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251.7 264.5 266.5 276.5 283.3
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Natural gas (mmcf/day) 590.4 617.8 620.1 615.7 640.0
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Total (mboe/day) 350.1 367.5 369.9 379.1 390.0
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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.
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2008 Gross Production Guidance Three
months
ended Year ended
Guidance Mar. 31 Dec. 31
2008 2008 2007
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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
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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
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Upstream Revenue Mix Three months
ended March 31
Percentage of upstream net revenues 2008 2007
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Crude oil & NGL
Light crude oil & NGL 44 51
Medium crude oil 8 6
Heavy crude oil & bitumen 29 21
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81 78
Natural gas 19 22
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100 100
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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 $28 million loss was recorded on an embedded derivative related to a drilling rig contract requiring payment in U.S. currency (refer to Note 15 to the Consolidated Financial Statements). The payments are expected to occur over the three-year period from mid-2008. The amount will fluctuate with the U.S./Cdn forward exchange rate until actual contract settlement.
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Netback Analysis
Three months ended March 31
2008 2007
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$ % (1) $ % (1)
Total
Crude oil equivalent (per boe) (2)
Gross price 69.37 49.67
Royalties 13.19 19 5.63 11
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Net sales price 56.18 44.04
Operating costs (3) 10.75 15 8.34 17
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Operating netback 45.43 35.70
DD&A 12.25 18 11.37 23
Administration expenses & other (3) 0.96 1 0.33 1
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Earnings before income taxes 32.22 47 24.00 48
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Canada
Crude oil equivalent (per boe) (2)
Gross price 68.23 48.99
Royalties 12.70 19 5.45 11
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Net sales price 55.53 43.54
Operating costs (3) 10.98 16 8.49 17
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Operating netback 44.55 35.05
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Western Canada
Crude oil (per boe) (2)
Light crude oil
Gross price 78.12 57.00
Royalties 10.20 13 6.20 11
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Net sales price 67.92 50.80
Operating costs (3) 16.59 21 11.95 21
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Operating netback 51.33 38.85
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Medium crude oil
Gross price 72.82 46.19
Royalties 13.39 18 7.96 17
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Net sales price 59.43 38.23
Operating costs (3) 14.55 20 13.56 29
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Operating netback 44.88 24.67
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Heavy crude oil & bitumen
Gross price 63.50 37.67
Royalties 8.22 13 4.72 13
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Net sales price 55.28 32.95
Operating costs (3) 14.95 24 11.84 31
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Operating netback 40.33 21.11
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Natural gas (per mcfge) (4)
Gross price 7.45 7.01
Royalties 1.42 19 1.44 21
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Net sales price 6.03 5.57
Operating costs (3) 1.53 21 1.33 19
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Operating netback 4.50 4.24
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East Coast
Light crude oil (per boe) (2)
Gross price 97.86 66.46
Royalties (5) 23.84 24 2.11 3
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Net sales price 74.02 64.35
Operating costs (3) 5.27 5 3.03 5
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Operating netback 68.75 61.32
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International
Light crude oil (per boe) (2)
Gross price 100.44 68.25
Royalties 26.54 26 10.35 15
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Net sales price 73.90 57.90
Operating costs (3) 4.63 5 4.90 7
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Operating netback 69.27 53.00
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(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.
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2008 Capital Expenditure Guidance (1)
(millions of dollars)
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Western Canada - oil & gas $ 1,670
- oil sands 300
East Coast Canada 650
International 430
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$ 3,050
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(1) Excludes capitalized administrative costs and capitalized interest.
The following table summarizes our capital expenditures for the periods
presented.
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Capital Expenditures Summary (1) Three months
ended March 31
(millions of dollars) 2008 2007
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Exploration
Western Canada $ 206 $ 165
East Coast Canada and Frontier 25 5
International 30 5
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261 175
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Development
Western Canada 469 388
East Coast Canada 68 54
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537 442
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$ 798 $ 617
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(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.
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Western Canada Wells Drilled Three months
ended March 31
2008 2007
Gross Net Gross Net
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Exploration Oil 23 23 20 20
Gas 57 49 65 56
Dry 20 19 9 9
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100 91 94 85
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Development Oil 120 104 138 130
Gas 116 87 168 137
Dry 3 3 10 10
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239 194 316 277
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Total 339 285 410 362
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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
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Upgrading Net Earnings Summary Three months
ended March 31
(millions of dollars, except where indicated) 2008 2007
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Gross margin $ 171 $ 138
Operating costs 63 58
Other recoveries (1) (1)
Depreciation and amortization 6 6
Income taxes 31 24
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Net earnings $ 72 $ 51
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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
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(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.
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Infrastructure and Marketing Net Earnings Summary Three months
ended March 31
(millions of dollars, except where indicated) 2008 2007
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Gross margin - pipeline $ 25 $ 26
- other infrastructure and marketing 89 72
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114 98
Other expenses 3 4
Depreciation and amortization 8 7
Income taxes 31 27
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Net earnings $ 72 $ 60
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Selected operating data:
Aggregate pipeline throughput (mbbls/day) 504 493
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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
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Canadian Refined Products Net Earnings Summary Three months
ended March 31
(millions of dollars, except where indicated) 2008 2007
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Gross margin - fuel sales $ 38 $ 42
- ancillary sales 10 9
- asphalt sales 19 13
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67 64
Operating and other expenses 4 18
Depreciation and amortization 20 16
Income taxes 13 10
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Net earnings $ 30 $ 20
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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
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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.
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U.S. Refining and Marketing Net Earnings Summary Three months
ended March 31
(millions of dollars, except where indicated) 2008
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Gross refining margin $ 87
Processing costs 53
Operating and other expenses 1
Interest - net 1
Depreciation and amortization 19
Income taxes 5
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Net earnings $ 8
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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
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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
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Corporate Summary Three months
ended March 31
(millions of dollars) income (expense) 2008 2007
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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
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Net earnings (loss) $ (12) $ (61)
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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.
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Foreign Exchange Summary Three months
ended March 31
(millions of dollars) 2008 2007
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(Gain) loss on translation of U.S. dollar
denominated long-term debt
Unrealized $ 44 $ (14)
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44 (14)
Cross currency swaps (14) 4
Other (gains) losses (20) 9
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$ 10 $ (1)
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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
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Corporate Capital Expenditures
Corporate capital expenditures totaled $12 million in the first three months of 2008 primarily for various o
