CALGARY, ALBERTA--(MARKET WIRE)--Apr 21, 2008 -- Husky Energy Inc. (Toronto:
HSE.TO -
News) 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
----------------------------------------------------------------------------
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 www.huskyenergy.com.
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 www.sec.gov and at www.huskyenergy.com.
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
maintenanceForward-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 payable 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 timing of payments during this
period will be determined by the capital expenditures made
at the refinery during this same period. The downstream
entity is included as part of the U.S. Refining and Marketing
segment. This entity is a self-sustaining foreign operation.
Both joint ventures are being accounted for using proportionate
consolidation. The amounts recorded in the financial statements
represent the Company's 50% interest in the joint ventures.
Note 7 Cash Flows - Change in Non-cash Working Capital
----------------------------------------------------------------------------
Three months
ended March 31
2008 2007
----------------------------------------------------------------------------
a) Change in non-cash working capital was as follows:
Decrease (increase) in non-cash working capital
Accounts receivable $ (324) $ 2
Inventories (248) 8
Prepaid expenses (1) (1)
Accounts payable and accrued liabilities 120 (585)
----------------------------------------------------------------------------
Change in non-cash working capital $ (453) $ (576)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Relating to:
Operating activities $ (297) $ (638)
Financing activities 9 218
Investing activities (165) (156)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
b) Other cash flow information:
Cash taxes paid $ 171 $ 768
Cash interest paid 41 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------Note 8 Bank Operating Loans
At March 31, 2008, the Company had unsecured short-term
borrowing lines of credit with banks totalling $270 million
(December 31, 2007 - $270 million). As at March 31, 2008,
bank operating loans were $77 million (December 31, 2007
- nil). As of March 31, 2008, letters of credit under these
lines of credit totalled $71 million (December 31, 2007
- $73 million).
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. As at March
31, 2008, there was no balance outstanding under this credit
facility.
Note 9 Long-term Debt
----------------------------------------------------------------------------
March 31 Dec. 31 March 31 Dec. 31
Maturity 2008 2007 2008 2007
----------------------------------------------------------------------------
Cdn $ Amount U.S. $ Denominated
Long-term debt
Medium-term notes 2009 $ 205 $ 203 $ - $ -
Bilateral credit facilities 2012 100 - - -
6.25% notes 2012 411 395 400 400
7.55% debentures 2016 205 198 200 200
6.20% notes 2017 308 296 300 300
6.15% notes 2019 308 296 300 300
8.90% capital securities 2028 231 223 225 225
6.80% notes 2037 463 445 450 450
Debt issue costs (1) (19) (20) - -
Unwound interest rate swaps 36 37 - -
----------------------------------------------------------------------------
$2,248 $2,073 $1,875 $1,875
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Long-term debt due within
one year
Bridge financing (2) 2008 $ 771 $ 741 $ 750 $ 750
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated using the effective interest rate method.
(2) The Company has the right to extend the maturity of the bridge financing
to June 26, 2009 by providing 30 days' notice.
Interest - net consisted of:
----------------------------------------------------------------------------
Three months
ended March 31
2008 2007
----------------------------------------------------------------------------
Long-term debt $ 48 $ 28
Short-term debt 1 1
----------------------------------------------------------------------------
49 29
Amount capitalized - (3)
----------------------------------------------------------------------------
49 26
Interest income (3) (5)
----------------------------------------------------------------------------
$ 46 $ 21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign exchange consisted of:
----------------------------------------------------------------------------
Three months
ended March 31
2008 2007
----------------------------------------------------------------------------
(Gain) loss on translation of U.S. dollar denominated
long-term debt $ 44 $ (14)
Cross currency swaps (14) 4
Other (gains) losses (20) 9
----------------------------------------------------------------------------
Loss (gain) $ 10 $ (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 10 Other Long-term Liabilities
Asset Retirement Obligations
Changes to asset retirement obligations were as follows:
----------------------------------------------------------------------------
Three months
ended March 31
2008 2007
----------------------------------------------------------------------------
Asset retirement obligations at beginning of year $ 662 $ 622
Liabilities incurred 18 8
Liabilities disposed (1) -
Liabilities settled (17) (14)
Accretion 13 12
----------------------------------------------------------------------------
Asset retirement obligations at end of year $ 675 $ 628
----------------------------------------------------------------------------
----------------------------------------------------------------------------At March 31, 2008, the estimated total undiscounted inflation-adjusted
amount required to settle outstanding asset retirement obligations
was $5.1 billion. These obligations will be settled based
on the useful lives of the underlying assets, which currently
extend an average of 30 years into the future. This amount
has been discounted using credit-adjusted risk free rates
ranging from 6.2% to 6.8%.
Note 11 Commitments and Contingencies
The Company has no material litigation other than various
claims and litigation arising in the normal course of business.
While the outcome of these matters is uncertain and there
can be no assurance that such matters will be resolved in
the Company's favour, the Company does not currently believe
that the outcome of adverse decisions in any pending or
threatened proceedings related to these and other matters
or any amount which it may be required to pay by reason
thereof would have a material adverse impact on its financial
position, results of operations or liquidity.
Note 12 Share Capital
The Company's authorized share capital consists of an unlimited
number of no par value common and preferred shares.
Common Shares
Changes to issued common shares were as follows:
----------------------------------------------------------------------------
Three months ended March 31
2008 2007
----------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
----------------------------------------------------------------------------
Balance at beginning of year 848,960,310 $ 3,551 848,537,018 $ 3,533
Options exercised 83,922 4 75,596 3
----------------------------------------------------------------------------
Balance at March 31 849,044,232 $ 3,555 848,612,614 $ 3,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------Stock Options
In accordance with the Company's stock option plan, common
share options may be granted to officers and certain other
employees. The stock option plan is a tandem plan that provides
the stock option holder with the right to exercise the option
or surrender the option for a cash payment. The exercise
price of the option is equal to the weighted average trading
price of the Company's common shares during the five trading
days prior to the date of the award. When the option is
surrendered for cash, the cash payment is the difference
between the weighted average trading price of the Company's
common shares on the trading day prior to the surrender
date and the exercise price of the option.
Under the terms of the original stock option plan, the options
awarded have a maximum term of five years and vest over
three years on the basis of one-third per year. Amendments
to the Company's stock option plan in 2007 also provided
for performance vesting of stock options. Performance options
granted may vest in up to one-third increments if the Company's
annual total shareholder return (stock price appreciation
and cumulative dividends on a reinvested basis) falls within
certain percentile ranks relative to its industry peer group.
The ultimate number of performance options that vest will
depend upon the Company's performance measured over three
calendar years. If the Company's performance is below the
specified level compared with its industry peer group, the
performance options awarded will be forfeited. If the Company's
performance is at or above the specified level compared
with its industry peer group, the number of performance
options exercisable shall be determined by the Company's
relative ranking.
The following tables cover all stock options granted by the Company for the
periods shown.
----------------------------------------------------------------------------
Three months ended March 31
2008 2007
----------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
----------------------------------------------------------------------------
Outstanding, beginning of year 30,131 $ 37.18 11,656 $ 16.40
Granted 2,029 $ 40.62 - $ -
Exercised for common shares (84) $ 11.81 (76) $ 12.00
Surrendered for cash (747) $ 13.12 (767) $ 12.06
Forfeited (243) $ 41.46 (244) $ 34.56
----------------------------------------------------------------------------
Outstanding at March 31 31,086 $ 38.02 10,569 $ 16.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Options exercisable at March 31 3,887 $ 15.33 3,877 $ 13.50
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, 2008
Outstanding Options Options Exercisable
----------------------------------------------------------------------------
Weighted Weighted Weighted
Number of Average Average Number of Average
Range of Options Exercise Contractual Options Exercise
Exercise Price (thousands) Prices Life (years) (thousands) Prices
----------------------------------------------------------------------------
$7.23 - $11.99 3,157 $ 11.70 1 3,157 $ 11.70
$12.00 - $17.99 115 $ 15.94 2 96 $ 15.62
$18.00 - $27.99 390 $ 26.17 3 144 $ 26.57
$28.00 - $36.99 942 $ 35.15 3 390 $ 34.63
$37.00 - $39.99 939 $ 39.39 4 100 $ 38.20
$40.00 - $40.99 2,447 $ 40.88 5 - $ -
$41.00 - $42.57 23,096 $ 41.69 4 - $ -
----------------------------------------------------------------------------
31,086 $ 38.02 4 3,887 $ 15.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 13 Employee Future Benefits
Total benefit costs recognized were as follows:
----------------------------------------------------------------------------
Three months
ended March 31
2008 2007
----------------------------------------------------------------------------
Employer current service cost $ 7 $ 6
Interest cost 3 2
Expected return on plan assets (3) (2)
Amortization of net actuarial losses 1 1
----------------------------------------------------------------------------
$ 8 $ 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------Note 14 Related Party Transactions
TransAlta Power, L.P. ("TAPLP") is under the indirect control
of Husky's principal shareholders. TAPLP is a 49.99% owner
in TransAlta Cogeneration, L.P. ("TACLP"), which is the
Company's joint venture partner for the Meridian cogeneration
facility at Lloydminster. The Company sells natural gas
to the Meridian cogeneration facility and other cogeneration
facilities owned by TACLP. These natural gas sales are related
party transactions and have been measured at the exchange
amount. For the three months ended March 31, 2008, the total
value of natural gas sales to the Meridian and other cogeneration
facilities owned by TACLP was $31 million. At March 31,
2008, the total value of accounts receivable related to
these transactions was $6 million.
Note 15 Financial Instruments and Risk Management
Details of the Company's significant accounting policies
for the recognition and measurement of financial instruments
and the basis for which income and expense are recognized
are disclosed in Note 3 of the Company's 2007 consolidated
financial statements.
Risk Management Overview
The Company is exposed to market risks related to the volatility
of commodity prices, foreign exchange rates and interest
rates. In certain instances, the Company uses derivative
instruments to manage the Company's exposure to these risks.
The Company employs risk management strategies and policies
to ensure that any exposures to risk are in compliance with
the Company's business objectives and risk tolerance levels.
Risk management is ultimately established by the Company's
Board of Directors and is implemented by senior management
and monitored by the risk management function within the
Company.
Fair Value of Financial Instruments
The Company's financial instruments as at March 31, 2008
included cash and cash equivalents, accounts receivable,
contribution receivable, bank operating loans, accounts
payable and accrued liabilities, contribution payable, long-term
debt, the derivative portion of cash flow and fair value
hedges and freestanding and embedded derivatives.
The carrying value of cash and cash equivalents, accounts
receivable, bank operating loans, accounts payable and accrued
liabilities approximates their fair value due to the short-term
maturity of these investments.
At March 31, 2008, the carrying value of the contribution
receivable and contribution payable was $1.2 billion and
$1.3 billion respectively. The fair value of these financial
instruments is not readily determinable due to uncertainties
regarding timing of the cash flows. Refer to Note 6, "Joint
Venture with BP."
The estimation of the fair value of commodity derivatives
incorporates forward prices and adjustments for quality
or location. The estimation of the fair value of interest
rate and foreign currency derivatives incorporates forward
market prices, which are compared to quotes received from
financial institutions to ensure reasonability.
The fair value of long-term debt is the present value of
future cash flows associated with the debt. Market information
such as treasury rates and credit spreads is used to determine
the appropriate discount rates. These fair value determinations
are compared to quotes received from financial institutions
to ensure reasonability. The estimated fair value of long-term
debt at the dates shown was:
----------------------------------------------------------------------------
March 31, 2008 December 31, 2007
Carrying Value Fair Value Carrying Value Fair Value
----------------------------------------------------------------------------
Long-term debt $3,019 $2,997 $2,814 $2,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------Market Risk
Market risk is the risk that the fair value of future cash
flows of a financial instrument will fluctuate because of
changes in market prices. Market risk is comprised of foreign
currency risk, interest rate risk and other price risk,
for example, commodity price risk. The objective of market
risk management is to manage and control market price exposures
within acceptable limits, while maximizing returns.
In certain instances, the Company uses derivative commodity
instruments to manage exposure to price volatility on a
portion of its oil and gas production and firm commitments
for the purchase or sale of crude oil and natural gas.
The Company's results are affected by the exchange rate
between the Canadian and U.S. dollar. The majority of the
Company's 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. 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. The majority of the Company's
expenditures are in Canadian dollars.
A change in the value of the Canadian dollar against the
U.S. dollar will also result in an increase or decrease
in the Company's U.S. dollar denominated debt, as expressed
in Canadian dollars, as well as the related interest expense.
In order to mitigate the Company's exposure to long-term
debt affected by the U.S./Canadian dollar exchange rate,
the Company has entered into cash flow hedges using cross
currency debt swaps. In addition, a portion of our U.S.
dollar denominated debt has been designated as a hedge of
a net investment in a self-sustaining foreign operation
and the unrealized foreign exchange gain is recorded in
Other Comprehensive Income.
To mitigate risk related to interest rates, the Company
enters into fair value hedges using interest rate swaps.
The Company's objectives, processes and policies for managing
market risk have not changed from the previous year.
Commodity Price Risk Management
Natural Gas Contracts
At March 31, 2008, the Company had the following third party
offsetting physical purchase and sale natural gas contracts,
which met the definition of a derivative instrument:
----------------------------------------------------------------------------
Volumes Fair
(mmcf) Value
----------------------------------------------------------------------------
Physical purchase contracts 29,149 $ 10
Physical sale contracts (29,149) $ (9)
----------------------------------------------------------------------------
----------------------------------------------------------------------------These contracts have been recorded at their fair value in
accounts receivable and the resulting unrealized gain or
loss has been recorded in other expenses in the consolidated
statement of earnings.
Interest Rate Risk Management
At March 31, 2008, the Company had entered into a fair value
hedge using interest rate swap arrangements whereby the
fixed interest rate coupon on the medium-term notes was
swapped to floating rates with the following terms:
----------------------------------------------------------------------------
Swap Rate Fair
Debt Amount Swap Maturity (percent) Value
----------------------------------------------------------------------------
6.95% medium-term notes $ 200 July 14, 2009 CDOR + 175 bps $ 5
----------------------------------------------------------------------------
----------------------------------------------------------------------------This contract has been recorded at fair value in other assets.
During the three months ended March 31, 2008, the Company
recognized a loss of less than $1 million (2007 - gain of
$1 million) on the interest rate swap arrangements.
Embedded Derivative
The Company entered into a contract with a Norwegian-based
company for drilling services offshore China. The contract
currency is U.S. dollars, which is not the functional currency
of either transacting party. As a result, this contract
has been identified as containing an embedded derivative
requiring bifurcation and separate accounting treatment
at fair value. This embedded derivative has been recorded
at fair value in accounts receivable and other assets and
the resulting unrealized loss has been recorded in other
expenses in the consolidated statement of earnings. At March
31, 2008, the fair value of the embedded derivative was
$73 million (December 31, 2007 - $101 million). In the first
quarter of 2008, the impact was an unrealized loss on the
embedded derivative of $28 million.
Foreign Currency Risk Management
The Company manages its exposure to foreign exchange fluctuations
by balancing the U.S. dollar denominated cash flows with
U.S. dollar denominated borrowings and other financial instruments.
Husky utilizes spot and forward sales to convert cash flows
to or from U.S. or Canadian currency.
At March 31, 2008, the Company had a cash flow hedge using the following
cross currency debt swaps:
----------------------------------------------------------------------------
Interest
Swap Canadian Rate Fair
Debt Amount Equivalent Swap Maturity (percent) Value
----------------------------------------------------------------------------
6.25% notes U.S. $ 150 $ 212 June 15, 2012 7.41 $ (71)
6.25% notes U.S. $ 75 $ 90 June 15, 2012 5.65 $ (10)
6.25% notes U.S. $ 50 $ 59 June 15, 2012 5.67 $ (6)
6.25% notes U.S. $ 75 $ 88 June 15, 2012 5.61 $ (8)
----------------------------------------------------------------------------
----------------------------------------------------------------------------These contracts have been recorded at fair value in other
long-term liabilities. The portion of the fair value of
the derivative related to foreign exchange losses has been
recorded in earnings to offset the foreign exchange on the
translation of the underlying debt. The remaining loss of
$5 million, net of tax of $2 million, has been included
in other comprehensive income. At March 31, 2008, the balance
in accumulated other comprehensive income was $4 million,
net of tax of $3 million. For the three months ended March
31, 2008, the Company recognized a foreign exchange gain
of $14 million (2007 - loss of $4 million) on the cross
currency debt swaps.
The Company enters into short-dated foreign exchange contracts
to fix the exchange rate for conversion of U.S. dollars
to Canadian dollars. During the first three months of 2008,
the impact of these contracts was a loss of $2 million (2007
- gain of less than $1 million).
The Company entered into forward purchases of U.S. dollars
to partially offset the fluctuations in foreign exchange
related to the contract for drilling services offshore China,
which contains an embedded derivative. At March 31, 2008,
the following foreign exchange transactions had been entered
into:
----------------------------------------------------------------------------
Forward Canadian Fair
Date Purchases Equivalent Value
----------------------------------------------------------------------------
October 5, 2007 U.S. $ 119 $ 117 $ 7
October 11, 2007 U.S. $ 119 $ 116 $ 7
October 29, 2007 U.S. $ 119 $ 115 $ 9
----------------------------------------------------------------------------
----------------------------------------------------------------------------These forward contracts have been recorded at fair value
in accounts receivable and other assets and the resulting
gain has been recorded in other expenses in the consolidated
statement of earnings. During the first three months of
2008, the impact was a gain of $15 million.
Effective July 1, 2007, the Company's U.S. $1.5 billion
of debt financing related to the Lima acquisition was designated
as a hedge of the Company's net investment in the U.S. refining
and marketing operations, which are considered self-sustaining.
As at March 31, 2008, the unrealized foreign exchange loss
of $51 million, net of tax of $9 million, arising from the
translation of the debt is recorded in other comprehensive
income.
Sensitivity Analysis
The Company is exposed to interest rate risk on its interest
rate swaps. As at March 31, 2008, had interest rates been
50 basis points higher or lower and assuming all other variables
remained constant, the impact to fair value would have been
less than $1 million. The impact to net earnings would have
been nil.
The Company is exposed to interest rate and foreign currency
risk on its cross currency debt swaps. Had the Canadian
dollar been 1% stronger versus the U.S. dollar and assuming
all other variables remained constant, the impact to other
comprehensive income would have been $4 million lower. As
at March 31, 2008, had the Canadian dollar been 1% weaker
versus the U.S. dollar and assuming all other variables
remained constant, the impact to other comprehensive income
would have been $6 million higher. As at March 31, 2008,
had the interest rates been 50 basis points higher and assuming
all other variables remained constant, the impact to other
comprehensive income would have been $2 million higher.
An equal and offsetting impact would have occurred had the
interest rates been 50 basis points lower and assuming all
other variables remained constant.
The Company is exposed to foreign currency risk on its embedded
derivative and its forward purchases of U.S. dollars to
partially offset the fluctuations in foreign exchange related
to the embedded derivative. As at March 31, 2008, had the
Canadian dollar been 1% stronger relative to the U.S. dollar
and assuming all other variables remained constant, the
impact to net earnings would have been $6 million higher
for the embedded derivative and $4 million lower for the
forward purchases of U.S. dollars. Equal and offsetting
impacts would have occurred had the Canadian dollar been
1% weaker relative to the U.S. dollar and assuming all other
variables remained constant.
Liquidity Risk
Liquidity risk is the risk that the Company will not be
able to meet its financial obligations as they become due.
The Company's processes for managing liquidity risk include
ensuring, to the extent possible, that it will have sufficient
liquidity to meet its liabilities when they become due.
The Company prepares annual capital expenditure budgets
which are monitored and are updated as required. In addition,
the Company requires authorizations for expenditures on
projects to assist with the management of capital.
Since the Company operates in the upstream oil and gas industry,
it requires sufficient cash to fund capital programs necessary
to maintain or increase production and develop reserves,
to acquire strategic oil and gas assets, to repay maturing
debt and to pay dividends. The Company's upstream capital
programs are funded principally by cash provided from operating
activities. However, during times of low oil and gas prices,
a portion of capital programs can generally be deferred.
However, due to the long cycle times and the importance
to future cash flow in maintaining the Company's production,
it may be necessary to utilize alternative sources of capital
to continue the Company's strategic investment plan during
periods of low commodity prices. As a result, the Company
frequently evaluates the options available with respect
to sources of long and short-term capital resources. Occasionally,
the Company will hedge a portion of its production to protect
cash flow in the event of commodity price declines. In addition,
the Company has access to a revolving syndicated credit
facility which allows the Company to borrow money from a
group of banks on an unsecured basis.
The following are the contractual maturities of financial liabilities as at
March 31, 2008:
----------------------------------------------------------------------------
1 to 2 to
Less than less than less than
Financial Liability 1 Year 2 Years 5 Years Thereafter
----------------------------------------------------------------------------
Accounts payable and accrued
liabilities $ 2,558 $ - $ - $ -
Bank operating loans 77 - - -
Cross currency swaps - - 447 -
Long-term debt and interest on
fixed rate debt 916 338 905 2,887
Other long-term liabilities 5 - - -
----------------------------------------------------------------------------
Total $ 3,556 $338 $1,352 $ 2,887
----------------------------------------------------------------------------
----------------------------------------------------------------------------The Company's contribution payable is payable between March
31, 2008 and December 31, 2015 with the final balance due
and payable by December 31, 2015.
The Company's objectives, processes and policies for managing
liquidity risk have not changed from the previous year.
Credit Risk
Credit risk represents the financial loss that the Company
would suffer if the Company's counterparties to a financial
instrument, in owing an amount to the Company, fail to meet
or discharge their obligation to the Company. The Company's
accounts receivables are predominantly with customers in
the energy industry and are subject to normal industry credit
risks. The Company's policy to mitigate credit risk is to
primarily deal with major financial institutions and investment
grade rated entities. The Company did not have any customers
that constituted more than 10% of total sales and operating
revenues during the first quarter of 2008.
Cash and cash equivalents include cash bank balances and
short-term deposits maturing in less than 30 days. The Company
manages the credit exposure related to short-term investments
by monitoring exposures daily on a per issuer basis relative
to predefined investment limits.
The carrying amount of accounts receivable and cash and
cash equivalents represents the maximum credit exposure.
The Company considers its accounts receivable excluding income taxes
receivable and doubtful accounts to be aged as follows:
----------------------------------------------------------------------------
March 31,
Aging 2008
----------------------------------------------------------------------------
Current $ 1,695
Past due (1 - 30 days) 223
Past due (31 - 60 days) -
Past due (61 - 90 days) 6
Past due (more than 90 days) 20
----------------------------------------------------------------------------
Total $ 1,944
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The movement in the Company's allowance for doubtful accounts for the first
quarter of 2008 was as follows:
----------------------------------------------------------------------------
Balance at January 1, 2008 $ 10
Provisions and revisions 1
----------------------------------------------------------------------------
Balance at March 31, 2008 $ 11
----------------------------------------------------------------------------
----------------------------------------------------------------------------For the first quarter of 2008, the Company wrote off less
than $1 million of uncollectible receivables.
The Company's objectives, processes and policies for managing
credit risk have not changed from the previous year.
Sale of Accounts Receivable
The Company has a securitization program to sell, on a revolving
basis, accounts receivable to a third party up to $350 million.
As at March 31, 2008, no accounts receivable had been sold
under the program (December 31, 2007 - nil).
Held-for-Trading Financial Liabilities
The Company's cross currency swaps have been designated
as a cash flow hedge and the derivative component of the
hedge meets the definition of a held-for-trading financial
liability. The cross currency swap counterparties' credit
profiles have not materially changed since the past year
or since inception. As a result, the amount of change during
the period and cumulatively in the fair value of the cross
currency swaps has not been materially impacted by changes
resulting from credit risk. At March 31, 2008, the amount
the Company would be contractually required to pay under
the cross currency swaps at maturity was $352 million higher
(December 31, 2007 - $341 million higher) than their carrying
amount.
Note 16 Capital Disclosures
The Company's objectives when managing capital are: (i)
to maintain a flexible capital structure, which optimizes
the cost of capital at acceptable risk; and (ii) to maintain
investor, creditor and market confidence to sustain the
future development of the business.
The Company manages its capital structure and makes adjustments
to it in light of changes in economic conditions and the
risk characteristics of our underlying assets. The Company
considers its capital structure to include shareholders'
equity, debt and working capital. To maintain or adjust
the capital structure, the Company may from time to time,
issue shares, raise debt and/or adjust its capital spending
to manage its current and projected debt levels.
The Company monitors capital based on the current and projected
ratios of debt to cash flow and debt to capital employed.
The Company's objective is to maintain a debt to cash flow
from operations ratio of less than two times. The ratio
may increase at certain times as a result of acquisitions.
To facilitate the management of this ratio, the Company
prepares annual budgets, which are updated depending on
varying factors such as general market conditions and successful
capital deployment. The annual budget is approved by the
Board of Directors.
The Company's share capital is not subject to external restrictions;
however the bilateral credit facilities, the syndicated
credit facility and the bridge credit facility all include
a debt to cash flow covenant. The Company was fully compliant
with this covenant at March 31, 2008.
There were no changes in the Company's approach to capital
management from the previous year.
Note 17 Subsequent Event
In April 2008, a subsidiary of the Company, Husky Oil Madura
Partnership ("HOMP"), entered into an agreement with CNOOC
Southeast Asia Limited ("CNOOCSE"), which resulted in the
acquisition by CNOOCSE of a 50% equity interest in Husky
Oil (Madura) Limited, a subsidiary of HOMP, for a consideration
of U.S. $125 million. Husky Oil (Madura) Limited holds a
100% interest in the Madura Strait Production Sharing Contract.
The resulting joint venture arrangement will be accounted
for using the proportionate consolidation method.
Husky Energy Inc. will host a conference call for analysts
and investors on Tuesday, April 22, 2008 at 8:30 a.m. Eastern
time to discuss Husky's first quarter results. To participate
please dial 1-800-319-4610 beginning at 8:15 a.m. Eastern
time.
Mr. John C.S. Lau, President & Chief Executive Officer,
and other officers will be participating in the call.
A live audio webcast of the conference call will be available
via Husky's website, www.huskyenergy.com
under Investor Relations. The webcast will be archived for
approximately 90 days.
Media are invited to listen to the conference call.
- Dial 1-800-597-1419 beginning at 8:20 a.m. (Eastern time)
A recording of the call will be available at approximately
9:30 a.m. (Eastern time)
- Dial 1-800-319-6413 (dial reservation # 2658)
The Postview will be available until May 22, 2008.