CALGARY, July 19 /PRNewswire-FirstCall/ - Husky Energy Inc. reported
net earnings of $978 million or $2.31 per share (diluted) in the second
quarter of 2006, up 148 percent from $394 million or $0.93 per share
(diluted) in the second quarter of 2005. Net earnings for the second
quarter of 2006 included tax benefits due to tax rate reductions of $328
million or $0.77 per share (diluted). Cash flow from operations in the
second quarter was $1.1 billion or $2.60 per share (diluted), a 33 percent
increase compared with $828 million or $1.95 per share (diluted) for the
same period in 2005. Sales and operating revenues, net of royalties, were
$3.0 billion in the second quarter of 2006, compared with $2.4 billion in
the second quarter of 2005.
"We are pleased with Husky's exploration success and White Rose project
execution," said Mr. John C.S. Lau, President & Chief Executive Officer,
Husky Energy Inc. "With a solid balance sheet and cash flow, Husky will
continue to benefit from its integrated business strategy and quality asset
base in this strong price environment."
Production in the second quarter of 2006 was 344,000 barrels of oil
equivalent per day, compared with 308,900 barrels of oil equivalent per day
in the second quarter of 2005. Total crude oil and natural gas liquids
production was 231,800 barrels per day, compared with 194,000 barrels per
day in the second quarter of 2005. Natural gas production was 672.8 million
cubic feet per day, compared with 689.3 million cubic feet per day in the
second quarter of 2005.
Husky's Tucker Oil Sands Project at Cold Lake, Alberta is on schedule
and on budget. Construction of the facility which will use steam-assisted
drainage technology (SAGD) is substantially complete. First steam is
planned in August of 2006 with first oil targeted for the fourth quarter.
During the production cycle, Husky expects to produce approximately 350
million barrels of bitumen with peak production of more than 30,000 barrels
per day.
At the Sunrise Oil Sands Project, work is progressing on the front-end
engineering design and Husky is continuing its evaluation of alternatives
for the downstream portion of the project.
Husky successfully acquired an additional 14,560 acres of oil sands
lease adjacent to its Saleski property. The acquisition increases Husky's
land holdings in Saleski from 178,560 acres to 193,120 acres and the
potential resources in Saleski to approximately 20.8 billion barrels of
original bitumen in place.
At the White Rose oil field, the fifth production well began producing
oil at the end of June and has increased reservoir production capacity to
approximately 110,000 barrels of oil per day. A sixth production well is
scheduled to come on stream at the end of 2006 and will further increase
reservoir production capacity to 125,000 barrels of oil per day.
In June, Husky made a hydrocarbon discovery at the White Rose O-28
delineation well in the western section of the White Rose oil field. Based
on the Company's current interpretation, the discovery at the O-28 well
could contain an additional potential recoverable resource of 40 to 90
million barrels of oil. The proved plus probable reserves in the White Rose
field were estimated at 240 million barrels (174 million barrels Husky's
share).
In the South China Sea, Husky made a significant hydrocarbon discovery
on the Liwan 3-1-1, Block 29/26. In accordance with the Company's current
interpretation of the 2-D seismic and drilling results, the discovery could
contain a potential recoverable resource of four to six trillion cubic feet
of natural gas. As such, it would be one of the largest natural gas
discoveries offshore China.
Offshore Indonesia, Husky was awarded the East Bawean II Block in the
East Java Sea, increasing its holdings in the region by 4,255 square
kilometres. The East Bawean II Block is located in the North East Java
Basin approximately 200 kilometres north of the Company's BD gas field in
the Madura Strait, offshore Indonesia. The acquisition of the East Bawean
ll Block increases Husky's total holdings in Indonesia to 7,049 square
kilometres or approximately 1.8 million acres. Husky holds a 100 percent
interest in the Madura Strait and East Bawean II blocks.
Construction of Husky's Lloydminster Ethanol Plant in Lloydminster,
Saskatchewan is essentially complete and commissioning activities have
commenced with full production expected in the third quarter of 2006. In
Minnedosa, Manitoba construction of the new ethanol plant is progressing on
schedule with start-up planned in the third quarter of 2007.
For the first six months of 2006, Husky's net earnings were $1.5
billion or $3.54 per share (diluted), compared with $778 million or $1.84
per share (diluted) for the same period in 2005, an increase of 93 percent.
Cash flow from operations for the first six months of 2006 was $2.1 billion
or $4.88 per share (diluted), compared with $1.6 billion or $3.88 per share
(diluted) for the same period in 2005.
Production in the first six months of 2006 was 348,700 barrels of oil
equivalent per day, compared with 314,200 barrels of oil equivalent per day
in the same period in 2005. Total crude oil and natural gas liquids
production was 235,500 barrels per day, compared with 200,400 barrels per
day during the first six months of 2005. Natural gas production was 679.0
million cubic feet per day, compared with 682.8 million cubic feet per day
in the first six months of 2005.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") July 19, 2006
This MD&A should be read in conjunction with the Consolidated Financial
Statements and related Notes. Readers are also encouraged to refer to
Husky's MD&A and Consolidated Financial Statements and 2005 Annual
Information Form filed in 2006 with Canadian regulatory agencies and Form
40-F filed with the Securities and Exchange Commission ("SEC"), the U.S.
regulatory agency. These documents are available at http://www.sedar.com and at
http://www.sec.gov.
Forward-looking Statements
This MD&A contains forward-looking statements. These statements are
based on certain estimates and assumptions and involve risks and
uncertainties. Actual results may differ materially. The reader is advised
to refer to Section 14.0 "Forward-looking Statements or Information" for
additional information.
Use of Pronouns and Other Terms Denoting Husky
In this MD&A the pronouns "we", "our" and "us" and the term "Husky"
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 June 30, 2006 are compared with
results for the three months ended June 30, 2005 and results for the six
months ended June 30, 2006 are compared with results for the six months
ended June 30, 2005. Discussions with respect to Husky's financial position
as at June 30, 2006 are compared with its financial position at December
31, 2005.
Additional Reader Guidance
- The Consolidated Financial Statements and comparative financial
information included in this Interim Report have been prepared in
accordance with Canadian generally accepted accounting principles
("GAAP").
- All dollar amounts are in millions of Canadian dollars, unless
otherwise indicated.
- Unless otherwise indicated, all production volumes quoted are gross,
which represent the Company's working interest share before royalties.
- Prices quoted include or exclude the effect of hedging as indicated.
1.0 SUMMARY OF QUARTERLY RESULTS
Husky's net earnings for the second quarter of 2006 were $978 million,
up $584 million compared with the second quarter of 2005. Included in net
earnings during the second quarter of 2006 are tax benefits amounting to
$328 million. These benefits relate to tax rate reductions by the
governments of Canada, Alberta and Saskatchewan that were all substantively
enacted during the quarter.
The White Rose oil field, which commenced operations in the fourth
quarter of 2005, contributed significantly to the positive variance in the
second quarter of 2006 as did higher crude oil prices. Unrealized gains
from foreign currency translation and lower stock-based compensation also
contributed to the higher net earnings in the second quarter. The positive
variance in the second quarter was partially offset by higher cash taxes,
lower natural gas prices, lower production volumes from the Terra Nova and
Wenchang oil fields and lower upgrading differentials.
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Financial Summary Three months ended
(millions of dollars, except June 30 March 31 Dec. 31 Sept. 30
per share amounts and ratios) 2006 2006 2005 2005
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Sales and operating revenues,
net of royalties $ 3,040 $ 3,104 $ 3,207 $ 2,594
Segmented earnings
Upstream $ 822 $ 412 $ 533 $ 445
Midstream 140 150 135 61
Refined Products 52 16 17 27
Corporate and eliminations (36) (54) (16) 23
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Net earnings $ 978 $ 524 $ 669 $ 556
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Per share - Basic $ 2.31 $ 1.24 $ 1.58 $ 1.31
- Diluted 2.31 1.24 1.58 1.31
Cash flow from operations 1,103 967 1,197 944
Per share - Basic 2.60 2.28 2.82 2.23
- Diluted 2.60 2.28 2.82 2.23
Dividends per common share 0.25 0.25 0.25 0.14
Special dividend per common share - - 1.00 -
Total assets 16,405 15,859 15,797 14,712
Total long-term debt including
current portion 1,722 1,838 1,886 1,896
Return on equity(1) (percent) 34.8 29.6 29.2 22.9
Return on average capital
employed(1) (percent) 28.2 23.2 22.8 17.9
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Financial Summary Three months ended
(millions of dollars, except June 30 March 31 Dec. 31 Sept. 30
per share amounts and ratios) 2005 2005 2004 2004
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Sales and operating revenues,
net of royalties $ 2,350 $ 2,094 $ 2,018 $ 2,191
Segmented earnings
Upstream $ 307 $ 239 $ 112 $ 161
Midstream 130 169 77 50
Refined Products 20 18 (3) 18
Corporate and eliminations (63) (42) 39 68
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Net earnings $ 394 $ 384 $ 225 $ 297
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Per share - Basic $ 0.93 $ 0.91 $ 0.53 $ 0.70
- Diluted 0.93 0.91 0.53 0.70
Cash flow from operations 828 816 469 571
Per share - Basic 1.95 1.93 1.11 1.34
- Diluted 1.95 1.93 1.11 1.34
Dividends per common share 0.14 0.12 0.12 0.12
Special dividend per common share - - 0.54 -
Total assets 14,058 13,690 13,240 12,901
Total long-term debt including
current portion 2,192 2,290 2,103 2,096
Return on equity(1) (percent) 20.2 18.3 17.0 17.7
Return on average capital
employed(1) (percent) 15.3 13.9 13.0 13.4
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(1) Calculated for the twelve months ended for the periods shown.
Western Canada crude oil production for the second quarter of 2006
remained at the same level as compared with the first quarter of 2006.
Natural gas sales volume decreased by 13 mmcf/day from the first quarter of
2006 to the second quarter of 2006. This decrease was primarily due to a
higher number of plant turnarounds and repairs, pipeline and sales
restrictions and tie-in delays.
In the second quarter of 2006, we drilled 45 gross (26 net) exploration
wells in the Western Canada Sedimentary Basin ("WCSB") resulting in 8 gross
(8 net) oil wells and 34 gross (16 net) gas wells. In the natural gas prone
deep basin, foothills and northern plains areas we drilled 9 gross (5.5
net) wells resulting in 8 gross (5.1 net) natural gas wells. At June 30,
2006, 6 gross (3.5 net) wells were drilling or suspended in these regions.
Following successful completion of a fourth production well in May
2006, Husky achieved 100 mbbls/day (72.5 mbbls/day Husky's share) of
production from the White Rose field. The field's production rates were
kept at an average rate of 85 mbbls/day (62 mbbls/day Husky's share) until
the fifth production well came on stream at the end of the quarter. The
addition of the fifth production well has increased the field's productive
capacity by 25 mbbls/day to 110 mbbls/day (80 mbbls/day Husky's share).
Terra Nova oil field production was 6.5 mbbls/day lower in the second
quarter of 2006 compared with the first quarter of 2006 as a result of
mechanical failure of components in the gearbox of both of the vessel's
main power generators. The FPSO subsequently suspended production
operations in early May and began preparing to disconnect from the riser
buoy prior to disembarking for dry dock and commencement of the 2006
turnaround. Production operations are expected to resume in late September
2006.
Wenchang oil field production declined by 1.4 mbbls/day in the second
quarter of 2006 compared with the first quarter of 2006 reflecting natural
reservoir decline.
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Daily Gross Production Three months ended
June 30 March 31 Dec. 31 Sept. 30 June 30
2006 2006 2005 2005 2005
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Crude oil and NGL
(mbbls/day)
Western Canada
Light crude oil & NGL 29.8 31.3 30.1 31.8 31.7
Medium crude oil 28.5 29.4 31.0 30.3 30.6
Heavy crude oil 105.6 109.5 109.5 103.3 100.9
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163.9 170.2 170.6 165.4 163.2
East Coast Canada
White Rose -
light crude oil 53.0 46.4 19.0 - -
Terra Nova -
light crude oil 2.8 9.3 12.2 10.2 13.5
China
Wenchang -
light crude oil 12.1 13.5 14.1 14.4 17.3
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231.8 239.4 215.9 190.0 194.0
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Natural gas (mmcf/day) 672.8 685.4 675.3 679.2 689.3
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Total (mboe/day) 344.0 353.6 328.5 303.2 308.9
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Production
During the first six months of 2006 White Rose was further developed
and Husky's share averaged 49.7 mbbls/day. This increase in production of
light crude was partially offset because the Terra Nova oil field was
shut-in to prepare to move the FPSO to dry dock.
2.0 STRATEGIC PLANS AND CAPABILITIES
We have several major projects that are at various stages of
development and, upon completion, are expected to result in sustained
growth in enterprise value.
Upstream
- East Coast Exploration and Development
- Oil Sands Development
- Mackenzie River Valley Exploration
- China and Indonesia Exploration and Development
Midstream
- Upgrader Expansion
Refined Products
- Refinery Modifications
- Ethanol Plant Construction
2.1 UPSTREAM
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Gross Production Six months Six months
ended Full Year ended Year ended
June 30 Forecast June 30 Dec. 31
2006 2006 2005 2005
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Crude oil & NGL (mbbls/day)
Light crude oil & NGL 99.0 103 - 116 63.3 64.6
Medium crude oil 29.0 29 - 32 31.5 31.1
Heavy crude oil 107.5 115 - 120 105.6 106.0
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235.5 247 - 268 200.4 201.7
Natural gas (mmcf/day) 679.0 680 - 730 682.8 680.0
Total barrels of
oil equivalent (mboe/day) 348.7 360 - 390 314.2 315.0
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Our foundation assets in the WCSB currently provide the majority of the
funding required to finance our strategic plans including our strategy with
respect to the optimal exploitation of the significant remaining resources
in the WCSB.
These exploitation activities involve increased drilling of infill and
step-out wells, the installation of various types of enhanced recovery
techniques, including thermal recovery of heavy oil and emerging
technologies such as alkaline surfactant polymer floods. In addition,
increased production from coalbed methane deposits is augmenting natural
gas production.
We also plan to maintain exploration activities focused on natural gas
prospects in the deep basin and the foothills and northern regions of
Alberta and British Columbia where natural gas reservoirs are deeper and
have been larger and prolific.
White Rose Oil Field
Following successful completion of a fourth production well, the White
Rose oil field achieved 100 mbbls/day (72.5 mbbls/day Husky's share) of
total production. Production rates were kept at an average rate of 85
mbbls/day (62 mbbls/day Husky's share) until the fifth production well came
on production at the end of the quarter. The addition of the fifth producer
has increased reservoir productive capacity to 110 mbbls/day total (80
mbbls/day Husky's share). A sixth production well, which is scheduled to
come on stream at the end of 2006, will further increase reservoir
productive capacity to 125 mbbls/day total (91 mbbls/day Husky's share).
Actual production will depend on the FPSO throughput capacity
limitation, which will be evaluated during the third quarter of 2006.
On June 20, 2006 we announced a hydrocarbon discovery at the White Rose
O-28 delineation well in the western section of the White Rose oil field.
The O-28 well was drilled on Significant Discovery Licence 1024 to depths
of up to 3,342 metres. The well revealed a 280 metre oil column in a
multi-layered reservoir in the Ben Nevis Avalon formation. An additional
side-track well is being drilled and logged to provide further information
about reservoir quality, continuity and hydrocarbon contacts. Based on our
current interpretation of the 3-D seismic and the O-28 well results, the
discovery could contain a potential recoverable gross resource of 40 to 90
million barrels of oil. Our share of this potential recoverable resource
will augment our proved and probable reserves which were approximately 173
million barrels of oil at the end of 2005. Husky plans to tie this western
extension of the oil field back to the SeaRose FPSO.
East Coast Canada Exploration
In the West Bonne Bay region of the Jeanne d'Arc Basin on Significant
Discovery Licence ("SDL") 1040, exploration drilling began during the
second quarter. West Bonne Bay is located just to the northeast of the
Terra Nova oil field. Under the terms of a farm-in agreement with Norsk
Hydro, who currently hold a 90 percent interest, we will earn a 25 percent
interest in SDL 1040 and an additional 7.5 percent in the North Ben Nevis
SDL 1008 where we hold a 65.6 percent interest.
A seismic vessel has been contracted to finish the 3-D seismic program
in the Jeanne d'Arc Basin that was halted last fall due to inclement
weather. This program, along with additional 3-D seismic shooting in the
vicinity of the White Rose and Terra Nova oil fields, will commence early
July.
Tucker Oil Sands Project
At the Tucker Oil Sands project, construction is substantially complete
and is on schedule to begin steam injection in August of 2006. Drilling and
well completions are 100 percent complete. Operational readiness has been
achieved with fully trained staff on-site. The project remains on schedule
to produce first oil in the fourth quarter of 2006.
Sunrise Oil Sands Project
During the second quarter of 2006 progress at Sunrise included
commencement of front-end engineering design, which is targeted to be
complete by the third quarter of 2007. Various facility configuration
studies are ongoing and collaborative work continued with various industry
participants on regional infrastructure, including an access highway and
airport. Modeling of the source water is ongoing and we plan to drill five
source water evaluation wells prior to year-end. An additional 10 source
water evaluation wells and 29 stratigraphic test wells are planned for the
winter drilling season. Pad locations and trajectories for phase one
horizontal wells are currently being determined.
Caribou and Saleski
During the second quarter we began evaluating core from stratigraphic
test well programs completed at Saleski and Caribou during the winter and
spring. Development planning is underway including water source and
disposal studies for both projects and determination of the appropriate
bitumen recovery process for Saleski.
Husky acquired one oil sands lease in the Saleski area of northern
Alberta at the July 12, 2006 Alberta land sale (Lease L0402 located in
Ranges 20 & 21, Township 87 W4M). The lease totals 14,560 acres and is
estimated to contain 1.3 billion barrels of bitumen in place within the
Grosmont and Nisku carbonate. The acquired lands are adjacent to Husky's
existing holdings in the Saleski area and resulted in an increase in
Husky's total land holdings from 178,560 acres to 193,120 acres (or from
279 sections to 302 sections) and increased Husky's bitumen in place
estimate for Saleski from 19.5 billion barrels to 20.8 billion barrels.
Northwest Territories Exploration
In May 2006 Husky announced a natural gas discovery at the Stewart D-57
well. The D-57 discovery was drilled on Tulita District Land Corporation
Freehold Block M-38. The well was drilled to a depth of 3,147 metres, cased
to total depth and suspended. On open-hole testing, natural gas flowed from
two Cretaceous intervals to the surface at a combined rate of 5 million
cubic feet per day, confirming a hydrocarbon bearing column of at least 50
metres. This is the first successful Cretaceous hydrocarbon discovery in
the Central Mackenzie region.
Husky also concluded its winter drilling program in the Summit Creek
area approximately 26 kilometres northwest of the Stewart D-57 discovery.
The program consisted of the Summit Creek K-44 well, an appraisal and
deeper pool exploration well adjacent to the Summit Creek B-44 discovery
well. Summit Creek K-44 was drilled on Exploration License ("EL") 397, 1.4
kilometres northeast of the B-44 discovery well. The well was drilled to a
depth of 3,130 metres, cased to total depth and suspended. The results are
being evaluated.
During the second quarter of 2006 we were awarded EL 441 (Block CMV-6),
flanking the eastern boundary of EL 397. The licence area contains
extensions of several plays from EL 397, including the Cretaceous natural
gas play recently confirmed by our Stewart D-57 well. The licence requires
a work commitment of $10.5 million over the next four years. We now hold
interests in approximately 3,275 square kilometers in the Central Mackenzie
Valley area.
Approximately 200 kilometres of seismic is being shot to better
identify prospects for this winter's drilling program on EL 397.
China Exploration
On June 14, 2006 we announced a significant hydrocarbon discovery at
Liwan 3-1-1, in the South China Sea.
Liwan 3-1-1 was drilled in a water depth of 1,500 metres on Block 29/26
in the Pearl River Mouth Basin and is the first deep water discovery made
offshore China. The block is located approximately 250 kilometres south of
Hong Kong. The well was drilled on existing 2-D seismic data to a total
depth of 3,843 metres on a large structure with 60 square kilometres of
closure and encountered 56 metres of net gas pay on logs over two zones.
The 2-D seismic interpretation prior to drilling the well indicated a
direct hydrocarbon response at the Liwan 3-1-1 location, which is present
over a majority of the 60 square kilometre closure currently mapped. The
porosity encountered in the pay zones averaged approximately 20 percent,
based on petrophysical interpretation.
The Liwan 3-1-1 well will be sidetracked for further evaluation of the
pay zone and we are currently planning a 3-D seismic survey for the near
future to assess a number of similar structures which have been identified
on 2-D seismic data. Further drilling on the block will follow after the
evaluation of the 3-D data. Based on our current interpretation of the 2-D
seismic and the Liwan 3-1-1 well results, the discovery could contain a
potential recoverable resource of four to six trillion cubic feet of
natural gas. China National Offshore Oil Corporation has the right to
participate in the development of any discoveries up to a 51 percent
working interest.
Also, in China, we are seeking tenders on a rig to drill an exploration
well on Block 04/35 in the East China Sea. The well is planned for late
2006.
Indonesia Natural Gas Development
At Madura, Indonesia, the conceptual design for the BD natural gas
field development has been submitted to the Indonesian regulatory agency,
BPMIGAS, for consideration. Negotiations on a gas sales agreement and
extension of the production sharing agreement continued through the second
quarter of 2006. Completion of this project is contingent on the timing of
government approval.
During the second quarter of 2006 we were awarded the Bawean II Block.
This block is located in the same basin as the Madura BD natural gas field
and contains similar prospects. We have committed to shoot 1,400 square
kilometres of seismic and drill two wells in the first exploration phase.
2.2 MIDSTREAM
We are currently implementing various pipeline and terminal expansion
initiatives coincident with the increasing level of upstream activity,
particularly in the heavy oil/bitumen corridor and south to the main
pipeline shipping systems at Hardisty, Alberta.
Lloydminster Upgrader
At the Lloydminster Upgrader the front-end engineering design with
respect to plans to expand throughput capacity from approximately 80 to 150
mbbls/day of synthetic crude oil and diluent commenced. The plans also
include modifications to the Upgrader that will permit processing of a 67
percent Cold Lake bitumen feedstock mix. During the second quarter of 2006
negotiations were completed and agreements executed with various process
licensors. Front-end engineering design work is expected to be completed by
the third quarter of 2007. Subject to project sanction, completion of the
expansion could be achieved by the end of 2010.
2.3 Refined Products
Prince George Refinery Low Sulphur Upgrade
At the Prince George refinery the second phase of modifications to
produce low sulphur diesel fuel is complete. The refinery now produces both
low sulphur gasoline and ultra low sulphur diesel consistent with
marketplace requirements. The refinery's design rate capacity is now 12
mbbls/day of low sulphur fuel, a 20 percent increase based on previously
stated capacity.
Lloydminster and Minnedosa Ethanol Plants
To meet the increasing demand for ethanol blended gasoline, which
currently ranges from 10 percent E-10 to 85 percent E-85 ethanol, we are
currently constructing two motor fuel grade ethanol plants. One plant is
located adjacent to our Upgrader at Lloydminster, Saskatchewan and the
other at Minnedosa, Manitoba, the site of our existing ethanol plant. Each
plant will have the same throughput capacity, producing 130 million litres
of ethanol per year.
Construction of the Lloydminster plant is essentially complete and is
in the final stages of commissioning.
Construction of the Minnedosa plant is approximately 20 percent
complete. The plant is expected to be ready for start-up during the third
quarter of 2007.
3.0 BUSINESS ENVIRONMENT
Husky's financial results are significantly influenced by its business
environment. Average quarterly market prices were:
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Average Benchmark Prices Three months ended
and U.S. Exchange Rate June 30 March 31 Dec. 31 Sept. 30 June 30
2006 2006 2005 2005 2005
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WTI crude oil(1)
(U.S. $/bbl) 70.70 63.48 60.02 63.10 53.17
Brent crude oil(2)
(U.S. $/bbl) 69.62 61.75 56.90 61.54 51.58
Canadian par light
crude 0.3% sulphur
($/bbl) 78.97 69.40 71.65 77.04 66.43
Lloyd heavy crude oil
@ Lloydminster
($/bbl) 48.65 26.25 29.60 44.13 27.95
NYMEX natural gas(1)
(U.S. $/mmbtu) 6.79 8.98 12.97 8.49 6.73
NIT natural gas ($/GJ) 5.95 8.79 11.08 7.75 6.99
WTI/Lloyd crude blend
differential
(U.S. $/bbl) 17.99 29.20 24.24 18.90 21.27
U.S./Canadian dollar
exchange rate (U.S. $) 0.891 0.866 0.852 0.833 0.804
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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.
3.1 COMMODITY PRICE RISK
Our earnings depend largely on the profitability of our upstream
business segment which is most significantly affected by fluctuations in
oil and gas prices. Commodity prices have been, and are expected to
continue to be, volatile due to a number of factors beyond our control. The
effect of any single risk is not determinable with certainty as these are
interdependent and our future course of action depends upon our assessment
of all information available at any given time.
Crude Oil
WTI and Husky Average Crude Oil Prices
WTI, the benchmark crude price, has escalated throughout the period
reported with some fluctuations, closely followed by Husky's light crude
prices.
The prices received for our crude oil and NGL are related to the price
of crude oil in world markets. Prices for heavy crude oil and other lesser
quality crudes trade at a discount or differential to light crude oil due
to the additional processing costs.
Following the typical seasonal lull in crude oil prices in the fourth
quarter of 2005 prices recovered to and then exceeded the U.S. $70.00/bbl
level ending the second quarter with a spot price of U.S. $73.94/bbl. The
environment for crude oil prices, in the near-term, remains unchanged as a
result of continued geopolitical strife and unpredictable weather patterns.
Natural Gas
NYMEX Natural Gas, NIT Natural Gas and Husky Average Natural Gas Prices
Both U.S. and Canadian benchmark natural gas prices have decreased in
2006. Husky's natural gas prices, which are dominated by floating prices,
followed suit.
The price of natural gas in North America is affected by regional
supply and demand factors, particularly those affecting the United States
such as weather conditions, pipeline delivery capacity, production
disruptions, the availability of alternative sources of less costly energy
supply, inventory levels and general industry activity levels. Periodic
imbalances between supply and demand for natural gas are common and result
in volatile pricing.
NYMEX natural gas prices peaked at the end of 2005, primarily as a
result of hurricane related shut-in production, after which mild winter
weather, high gas storage levels and mandatory draw downs caused prices to
decline rapidly through the first quarter of 2006. Prices during the second
quarter of 2006 fluctuated in the range of U.S. $6.00/mmbtu and U.S.
$7.50/mmbtu and ended the quarter at U.S. $5.89/mmbtu for July deliveries.
Other Business Environment Risks
Please refer to our 2005 MD&A for a discussion about other business
environment risks.
3.2 SENSITIVITY ANALYSIS
The following table indicates the relative annual effect of changes in
certain key variables on our pre-tax cash flow and net earnings. The
analysis is based on business conditions and production volumes during the
second quarter of 2006. Each separate item in the sensitivity analysis
shows the effect of an increase in that variable only; all other variables
are held constant. While these sensitivities are applicable for the period
and magnitude of changes on which they are based, they may not be
applicable in other periods, under other economic circumstances or greater
magnitudes of change.
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Sensitivity Analysis
2006
Second
Quarter
Average Increase
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Upstream and Midstream
WTI benchmark crude oil price 70.70 U.S. $1.00/bbl
NYMEX benchmark natural gas price(1) 6.79 U.S. $0.20/mmbtu
WTI/Lloyd crude blend differential(2) 17.99 U.S. $1.00/bbl
Exchange rate (U.S. $ per Cdn $)(3) 0.89 U.S. $0.01
Refined Products
Light oil margins 0.05 Cdn $0.005/litre
Asphalt margins 12.51 Cdn $1.00/bbl
Consolidated
Period end translation of U.S. $ debt
(U.S. $ per Cdn $) 0.90(4) U.S. $0.01
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effect on Pre-tax Effect on
Cash Flow Net Earnings
-------------------------------------------------------------------------
($ millions) ($/ ($ millions) ($/
share) share)
(5) (5)
Upstream and Midstream
WTI benchmark crude oil price 82 0.19 55 0.13
NYMEX benchmark natural gas price(1) 34 0.08 23 0.05
WTI/Lloyd crude blend differential(2) (29) (0.07) (19) (0.04)
Exchange rate (U.S. $ per Cdn $)(3) (68) (0.16) (46) (0.11)
Refined Products
Light oil margins 16 0.04 10 0.02
Asphalt margins 9 0.02 6 0.01
Consolidated
Period end translation of U.S. $ debt
(U.S. $ per Cdn $) 8 0.02
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes decrease in earnings related to natural gas consumption.
(2) Includes impact of upstream and upgrading operations only.
(3) Assumes no foreign exchange gains or losses on U.S. dollar
denominated long-term debt and other monetary items.
(4) U.S./Canadian dollar exchange rate at June 30, 2006.
(5) Based on June 30, 2006 common shares outstanding of 424.2 million.
4.0 RESULTS OF OPERATIONS
Quarterly Segmented Earnings
Husky's profitability is largely dependant on Upstream operations,
partially supported by upgrading results during times when light/heavy
crude oil differentials are wider.
4.1 UPSTREAM
Second Quarter
Upstream earnings were $515 million higher in the second quarter of
2006 than in the second quarter of 2005 as a result of the following
factors:
- higher sales volume of light and heavy crude oil;
- higher light, medium and heavy crude oil prices; and
- lower income taxes resulting from rate reductions.
Partially offset by:
- lower sales volume of medium crude oil and natural gas;
- lower natural gas prices;
- higher unit operating costs; and
- higher unit depletion, depreciation and amortization.
Six Months
The factors that affected results for the second quarter were primarily
responsible for variances in results for the six months ended June 30, 2006
except for natural gas prices, which were higher during the six month
period in 2006 compared with the same period in 2005.
-------------------------------------------------------------------------
Upstream Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars) 2006 2005 2006 2005
-------------------------------------------------------------------------
Gross revenues $ 1,658 $ 1,154 $ 3,151 $ 2,194
Royalties 207 178 413 330
-------------------------------------------------------------------------
Net revenues 1,451 976 2,738 1,864
Operating and
administration expenses 308 249 619 489
Depletion, depreciation
and amortization 354 278 705 551
Income taxes (33) 142 180 278
-------------------------------------------------------------------------
Earnings $ 822 $ 307 $ 1,234 $ 546
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net Revenue Variance Analysis
Crude oil Natural
(millions of dollars) & NGL gas Other Total
-------------------------------------------------------------------------
Three months ended
June 30, 2005 $ 624 $ 332 $ 20 $ 976
Price changes 353 (49) - 304
Volume changes 205 (10) - 195
Royalties (60) 31 - (29)
Processing and sulphur - - 5 5
-------------------------------------------------------------------------
Three months ended
June 30, 2006 $ 1,122 $ 304 $ 25 $ 1,451
-------------------------------------------------------------------------
Six months ended
June 30, 2005 $ 1,197 $ 631 $ 36 $ 1,864
Price changes 490 75 - 565
Volume changes 384 (4) - 380
Royalties (84) - - (84)
Processing and sulphur - - 13 13
-------------------------------------------------------------------------
Six months ended
June 30, 2006 $ 1,987 $ 702 $ 49 $ 2,738
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Unit Operating Costs
Unit operating costs were six percent higher in the second quarter of
2006 compared with the same period in 2005 due to higher costs for energy,
labour, servicing natural gas compression, higher natural gas well count
and production declines. The high level of industry activity has created
increased demand for, and consequently, higher prices for oil field
materials and services.
NETBACK AND UNIT OPERATING COST
Higher netbacks resulting from higher crude oil prices are only
marginally offset by increases in operating costs.
Unit Depletion, Depreciation and Amortization
Unit depletion, depreciation and amortization expense increased 15
percent in the second quarter of 2006 compared with the same period in
2005. The increase was primarily due to net growth of the capital base in
2006 as a result of increased requirements for production maintenance
capital for our properties in the WCSB, and the start-up of the White Rose
oil field, which, since it is an offshore development, has a higher ratio
of capital to reserves. In addition, the higher energy costs, as with
operating costs, increased the cost of materials and services embedded in
our capital costs.
-------------------------------------------------------------------------
Average Sales Prices Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Crude Oil ($/bbl)
Light crude oil & NGL $ 73.74 $ 59.51 $ 70.35 $ 57.95
Medium crude oil 58.42 40.45 48.29 38.42
Heavy crude oil 48.12 27.95 26.73 25.13
Total average 60.18 40.09 52.54 37.59
Natural Gas ($/mcf)
Average 5.95 6.76 7.01 6.42
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Effective Royalty Rates Three months Six months
Percentage of upstream ended June 30 ended June 30
sales revenues 2006 2005 2006 2005
-------------------------------------------------------------------------
Crude oil & NGL 12% 13% 11% 13%
Natural gas 15% 20% 18% 20%
Total 13% 16% 13% 15%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Upstream Revenue Mix Three months Six months
Percentage of upstream sales ended June 30 ended June 30
revenues, after royalties 2006 2005 2006 2005
-------------------------------------------------------------------------
Light crude oil & NGL 41% 31% 42% 31%
Medium crude oil 8% 10% 8% 10%
Heavy crude oil 28% 23% 23% 23%
Natural gas 23% 36% 27% 36%
-------------------------------------------------------------------------
100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Operating Netbacks
WCSB East Coast
Three months ended June 30 2006 2005 2006 2005
-------------------------------------------------------------------------
Light Crude Oil (per boe)(1)
Sales Price $ 62.34 $ 57.50 $ 76.57 $ 58.11
Royalties 7.14 7.64 1.82 2.86
Operating costs 12.88 11.26 4.97 3.29
-------------------------------------------------------------------------
42.32 38.60 69.78 51.96
-------------------------------------------------------------------------
Medium Crude Oil (per boe)(1)
Sales Price 57.34 40.61 - -
Royalties 10.76 6.98 - -
Operating costs 11.52 10.05 - -
-------------------------------------------------------------------------
35.06 23.58 - -
-------------------------------------------------------------------------
Heavy Crude Oil (per boe)(1)
Sales Price 47.92 28.09 - -
Royalties 6.34 3.09 - -
Operating costs 10.28 9.48 - -
-------------------------------------------------------------------------
31.30 15.52 - -
-------------------------------------------------------------------------
Total Crude Oil (per boe)(1)
Sales Price 52.08 35.64 76.57 58.11
Royalties 7.28 4.65 1.82 2.86
Operating costs 10.95 9.90 4.97 3.29
-------------------------------------------------------------------------
33.85 21.09 69.78 51.96
-------------------------------------------------------------------------
Natural Gas (per mcfge)(2)
Sales Price 6.23 6.81 - -
Royalties 1.16 1.51 - -
Operating costs 1.09 1.00 - -
-------------------------------------------------------------------------
3.98 4.30 - -
-------------------------------------------------------------------------
Equivalent Unit (per boe)(1)
Sales Price 46.13 37.81 76.57 58.11
Royalties 7.15 6.49 1.82 2.86
Operating costs 9.17 8.26 4.97 3.29
-------------------------------------------------------------------------
$ 29.81 $ 23.06 $ 69.78 $ 51.96
-------------------------------------------------------------------------
-------------------------------------------------------------------------
International Total
Three months ended June 30 2006 2005 2006 2005
-------------------------------------------------------------------------
Light Crude Oil (per boe)(1)
Sales Price $ 77.80 $ 66.11 $ 72.56 $ 60.20
Royalties 16.35 6.16 5.21 6.09
Operating costs 2.41 2.39 6.95 6.91
-------------------------------------------------------------------------
59.04 57.56 60.40 47.20
-------------------------------------------------------------------------
Medium Crude Oil (per boe)(1)
Sales Price - - 57.34 40.61
Royalties - - 10.76 6.98
Operating costs - - 11.52 10.05
-------------------------------------------------------------------------
- - 35.06 23.58
-------------------------------------------------------------------------
Heavy Crude Oil (per boe)(1)
Sales Price - - 47.92 28.09
Royalties - - 6.34 3.09
Operating costs - - 10.28 9.48
-------------------------------------------------------------------------
- - 31.30 15.52
-------------------------------------------------------------------------
Total Crude Oil (per boe)(1)
Sales Price 77.80 66.11 59.28 39.96
Royalties 16.35 6.16 6.44 4.66
Operating costs 2.41 2.39 9.07 8.79
-------------------------------------------------------------------------
59.04 57.56 43.77 26.51
-------------------------------------------------------------------------
Natural Gas (per mcfge)(2)
Sales Price - - 6.23 6.81
Royalties - - 1.16 1.51
Operating costs - - 1.09 1.00
-------------------------------------------------------------------------
- - 3.98 4.30
-------------------------------------------------------------------------
Equivalent Unit (per boe)(1)
Sales Price 77.80 66.11 52.19 40.29
Royalties 16.35 6.16 6.61 6.31
Operating costs 2.41 2.39 8.24 7.74
-------------------------------------------------------------------------
$ 59.04 $ 57.56 $ 37.34 $ 26.24
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Includes associated co-products converted to mcfge.
-------------------------------------------------------------------------
WCSB East Coast
Six months ended June 30 2006 2005 2006 2005
-------------------------------------------------------------------------
Light Crude Oil (per boe)(1)
Sales Price $ 61.50 $ 53.92 $ 73.14 $ 59.42
Royalties 6.27 6.23 2.75 2.94
Operating costs 12.32 10.53 6.15 3.61
-------------------------------------------------------------------------
42.91 37.16 64.24 52.87
-------------------------------------------------------------------------
Medium Crude Oil (per boe)(1)
Sales Price 47.83 38.49 - -
Royalties 8.51 6.69 - -
Operating costs 12.02 10.30 - -
-------------------------------------------------------------------------
27.30 21.50 - -
-------------------------------------------------------------------------
Heavy Crude Oil (per boe)(1)
Sales Price 37.34 25.28 - -
Royalties 4.71 2.62 - -
Operating costs 10.76 9.35 - -
-------------------------------------------------------------------------
21.87 13.31 - -
-------------------------------------------------------------------------
Total Crude Oil (per boe)(1)
Sales Price 43.32 32.95 73.14 59.42
Royalties 5.66 4.06 2.75 2.94
Operating costs 11.25 9.75 6.15 3.61
-------------------------------------------------------------------------
26.41 19.14 64.24 52.87
-------------------------------------------------------------------------
Natural Gas (per mcfge)(2)
Sales Price 7.15 6.50 - -
Royalties 1.54 1.45 - -
Operating costs 1.04 0.97 - -
-------------------------------------------------------------------------
4.57 4.08 - -
-------------------------------------------------------------------------
Equivalent Unit (per boe)(1)
Sales Price 43.14 35.36 73.14 59.42
Royalties 7.09 5.91 2.75 2.94
Operating costs 9.24 8.19 6.15 3.61
-------------------------------------------------------------------------
$ 26.81 $ 21.26 $ 64.24 $ 52.87
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
International Total
Six months ended June 30 2006 2005 2006 2005
-------------------------------------------------------------------------
Light Crude Oil (per boe)(1)
Sales Price $ 75.58 $ 62.42 $ 70.06 $ 57.61
Royalties 10.83 5.78 4.85 5.37
Operating costs 3.11 2.38 7.55 6.70
-------------------------------------------------------------------------
61.64 54.26 57.66 45.54
-------------------------------------------------------------------------
Medium Crude Oil (per boe)(1)
Sales Price - - 47.83 38.49
Royalties - - 8.51 6.69
Operating costs - - 12.02 10.30
-------------------------------------------------------------------------
- - 27.30 21.50
-------------------------------------------------------------------------
Heavy Crude Oil (per boe)(1)
Sales Price - - 37.34 25.28
Royalties - - 4.71 2.62
Operating costs - - 10.76 9.35
-------------------------------------------------------------------------
- - 21.87 13.31
-------------------------------------------------------------------------
Total Crude Oil (per boe)(1)
Sales Price 75.58 62.42 52.12 37.36
Royalties 10.83 5.78 5.25 4.13
Operating costs 3.11 2.38 9.60 8.69
-------------------------------------------------------------------------
61.64 54.26 37.27 24.54
-------------------------------------------------------------------------
Natural Gas (per mcfge)(2)
Sales Price - - 7.15 6.50
Royalties - - 1.54 1.45
Operating costs - - 1.04 0.97
-------------------------------------------------------------------------
- - 4.57 4.08
-------------------------------------------------------------------------
Equivalent Unit (per boe)(1)
Sales Price 75.58 62.42 49.14 37.94
Royalties 10.83 5.78 6.53 5.77
Operating costs 3.11 2.38 8.52 7.67
-------------------------------------------------------------------------
$ 61.64 $ 54.26 $ 34.09 $ 24.50
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Includes associated co-products converted to mcfge.
Upstream Capital Expenditures
-------------------------------------------------------------------------
Capital Expenditures Summary(1) Three months Six months
ended June 30 ended June 30
(millions of dollars) 2006 2005 2006 2005
-------------------------------------------------------------------------
Exploration
Western Canada $ 153 $ 153 $ 320 $ 314
East Coast Canada
and Frontier 4 14 25 18
International 36 19 37 23
-------------------------------------------------------------------------
193 186 382 355
-------------------------------------------------------------------------
Development
Western Canada 244 223 757 594
East Coast Canada 111 126 163 246
International 6 1 9 3
-------------------------------------------------------------------------
361 350 929 843
-------------------------------------------------------------------------
$ 554 $ 536 $ 1,311 $ 1,198
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period.
Upstream capital expenditures totaled $1,311 million, 84 percent of
total consolidated capital expenditures during the first six months of 2006
compared with $1,198 million or 91 percent of the total, during the first
six months of 2005.
-------------------------------------------------------------------------
Western Canada Wells Three months Six months
Drilled(1)(2) ended June 30 ended June 30
2006 2005 2006 2005
Gross Net Gross Net Gross Net Gross Net
-------------------------------------------------------------------------
Exploration Oil 8 8 10 10 30 30 35 32
Gas 34 16 36 21 196 100 132 93
Dry 3 2 5 5 19 17 19 19
-------------------------------------------------------------------------
45 26 51 36 245 147 186 144
-------------------------------------------------------------------------
Development Oil 70 59 65 58 196 171 131 119
Gas 30 22 47 44 254 216 278 265
Dry 2 2 5 5 11 11 15 15
-------------------------------------------------------------------------
102 83 117 107 461 398 424 399
-------------------------------------------------------------------------
Total 147 109 168 143 706 545 610 543
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Excludes stratigraphic test wells.
(2) Includes non-operated wells.
4.2 MIDSTREAM
Second Quarter
Upgrading earnings decreased in the second quarter of 2006 by $18
million compared with the second quarter of 2005 due to:
- narrower upgrading differential; and
- lower sales volume of synthetic crude oil due to an outage for
compressor repairs.
Partially offset by:
- lower natural gas and steam costs; and
- lower income taxes and adjustment for tax rate reductions.
Six Months
The factors that affected results for the second quarter were primarily
responsible for variances in the results for the six months ended June 30,
2006.
-------------------------------------------------------------------------
Upgrading Earnings Summary Three months Six months
(millions of dollars, ended June 30 ended June 30
except where indicated) 2006 2005 2006 2005
-------------------------------------------------------------------------
Gross margin $ 136 $ 195 $ 344 $ 402
Operating costs 53 53 119 103
Other recoveries (2) (2) (3) (3)
Depreciation and amortization 6 4 12 9
Income taxes - 43 44 89
-------------------------------------------------------------------------
Earnings $ 79 $ 97 $ 172 $ 204
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Upgrader throughput(1)
(mbbls/day) 68.8 71.3 70.1 71.7
Synthetic crude oil sales
(mbbls/day) 56.9 60.1 60.2 62.0
Upgrading differential
($/bbl) $ 22.73 $ 31.05 $ 28.73 $ 31.51
Unit margin ($/bbl) $ 26.35 $ 35.64 $ 31.61 $ 35.80
Unit operating cost(2)
($/bbl) $ 8.39 $ 8.12 $ 9.33 $ 7.91
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.
-------------------------------------------------------------------------
Upgrading Earnings Variance Analysis
(millions of dollars)
-------------------------------------------------------------------------
Three months ended June 30, 2005 $ 97
Volume (10)
Margin (49)
Operating costs - energy related 5
Operating costs - non-energy related (5)
Depreciation and amortization (2)
Income taxes 43
-------------------------------------------------------------------------
Three months ended June 30, 2006 $ 79
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2005 $ 204
Volume (12)
Margin (46)
Operating costs - energy related (4)
Operating costs - non-energy related (12)
Depreciation and amortization (3)
Income taxes 45
-------------------------------------------------------------------------
Six months ended June 30, 2006 $ 172
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Second Quarter
Infrastructure and marketing earnings increased by $28 million in the
second quarter of 2006 compared with the second quarter of 2005 due to:
- higher income associated with marketing natural gas and blended heavy
crude oil;
- higher pipeline margins; and
- lower income taxes including an adjustment for tax rate reductions.
Six Months
The factors that affected results for the second quarter were primarily
responsible for variances in the results for the six months ended June 30,
2006 except that earnings from marketing blended heavy crude oil were lower
than the comparable six month period in 2005.
-------------------------------------------------------------------------
Infrastructure and Marketing
Earnings Summary Three months Six months
(millions of dollars, ended June 30 ended June 30
except where indicated) 2006 2005 2006 2005
-------------------------------------------------------------------------
Gross margin - pipeline $ 28 $ 22 $ 54 $ 47
- other
infrastructure
and marketing 52 39 120 116
-------------------------------------------------------------------------
80 61 174 163
Other expenses 3 2 5 5
Depreciation and amortization 5 6 11 11
Income taxes 11 20 40 52
-------------------------------------------------------------------------
Earnings $ 61 $ 33 $ 118 $ 95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline
throughput (mbbls/day) 480 488 490 499
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Midstream Capital Expenditures
Midstream capital expenditures totaled $87 million in the first six
months of 2006; $75 million at the Lloydminster Upgrader, primarily for
debottleneck and reliability projects and $12 million on pipelines and
infrastructure.
4.3 REFINED PRODUCTS
Second Quarter
Refined products earnings increased by $32 million in the second
quarter of 2006 compared with the second quarter of 2005 due to:
- higher marketing margins for gasoline and distillates; and
- higher sales volume of asphalt products.
Partially offset by:
- higher depreciation expense for the Prince George refinery and
marketing outlets.
Six Months
The factors that affected results for the second quarter were primarily
responsible for variances in the results for the six months ended June 30,
2006.
-------------------------------------------------------------------------
Refined Products
Earnings Summary Three months Six months
(millions of dollars, ended June 30 ended June 30
except where indicated) 2006 2005 2006 2005
-------------------------------------------------------------------------
Gross margin - fuel sales $ 57 $ 24 $ 79 $ 53
- ancillary
sales 8 9 16 16
- asphalt sales 32 28 53 47
-------------------------------------------------------------------------
97 61 148 116
Operating and other expenses 19 19 35 36
Depreciation and amortization 13 11 23 20
Income taxes 13 11 22 22
-------------------------------------------------------------------------
Earnings $ 52 $ 20 $ 68 $ 38
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Selected operating data:
Number of fuel outlets 506 521
Light oil sales
(million litres/day) 8.6 8.8 8.6 8.6
Light oil retail sales
per outlet
(thousand litres/day) 12.2 12.2 12.5 12.3
Prince George refinery
throughput (mbbls/day)(1) 3.7 9.5 6.5 9.8
Asphalt sales (mbbls/day) 24.9 19.7 21.3 18.7
Lloydminster refinery
throughput (mbbls/day) 25.4 21.6 26.2 24.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Prince George throughput decreased in the second quarter of 2006 as a
result of a plant shutdown for the commissioning of the low sulphur
diesel modifications.
Refined Products Capital Expenditures
Refined Products capital expenditures totaled $143 million in the first
six months of 2006; $32 million at the Prince George refinery, $64 million
at the Lloydminster ethanol plant and $40 million at the Minnedosa ethanol
plant.
4.4 CORPORATE
Second Quarter
Corporate expense decreased by $27 million in the second quarter of
2006 compared with the second quarter of 2005 due to:
- gains on translation of U.S. denominated debt in the second quarter
2006 compared with losses in the second quarter of 2005; and
- lower stock-based compensation expense during the second quarter
of 2006.
Partially offset by:
- lower capitalized interest due to start-up of the White Rose oil
field; and
- higher profit elimination on inventory on-hand at the end of the
second quarter of 2006.
Six Months
The factors that affected results for the second quarter were primarily
responsible for variances in the results for the six months ended June 30,
2006.
-------------------------------------------------------------------------
Corporate Summary Three months Six months
ended June 30 ended June 30
(millions of dollars)
income (expense) 2006 2005 2006 2005
-------------------------------------------------------------------------
Intersegment
eliminations - net $ (23) $ 14 $ (14) $ (9)
Administration
expenses (8) (5) (12) (11)
Stock-based
compensation (15) (77) (85) (98)
Accretion (1) (1) (1) (1)
Other - net (4) (3) (8) (6)
Depreciation and
amortization (5) (5) (11) (11)
Interest on debt (32) (37) (70) (72)
Interest capitalized 10 31 21 55
Interest income - - - 1
Foreign exchange
- realized (8) (1) 19 5
Foreign exchange
- unrealized 40 (19) 18 (32)
Income taxes 10 40 53 74
-------------------------------------------------------------------------
Loss $ (36) $ (63) $ (90) $ (105)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Foreign Exchange Rates Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of
period U.S. $0.857 U.S. $0.827 U.S. $0.858 U.S. $0.831
At end of period U.S. $0.897 U.S. $0.816 U.S. $0.897 U.S. $0.816
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Income Taxes
During the second quarter of 2006 consolidated income taxes consisted
of $210 million of current taxes and a recovery of future taxes of $229
million compared with current taxes of $75 million and future taxes of $101
million in the same period of 2005.
The recovery of future taxes in the second quarter of 2006 resulted
from recording non-recurring tax benefits of $328 million that arose due to
changes in the tax rates for the governments of Canada ($198 million),
Alberta ($90 million) and Saskatchewan ($40 million). All of this tax
legislation received royal assent and was, therefore, substantively enacted
in the second quarter of 2006.
The increase in current taxes in the second quarter of 2006 compared
with the second quarter of 2005 was due to higher taxable income.
Corporate Capital Expenditures
Corporate capital expenditures totaled $13 million in the first six
months of 2006 primarily for various office and information system
upgrades.
5.0 LIQUIDITY AND CAPITAL RESOURCES
During the second quarter cash flow from operating activities financed
all of our capital requirements and dividend payment. At June 30, 2006 we
had $1.4 billion in unused committed credit facilities.
5.1 OPERATING ACTIVITIES
In the second quarter of 2006, cash generated from operating activities
amounted to $1,302 million compared with $771 million in the second quarter
of 2005. Higher cash flow from operating activities was primarily due to
higher commodity prices, higher production volumes and a higher change in
non-cash working capital.
5.2 FINANCING ACTIVITIES
In the second quarter of 2006, cash used in financing activities
amounted to $339 million compared with $192 million in the second quarter
of 2005. During the second quarter of 2006, higher dividends and non-cash
working capital associated with financing activities primarily resulted in
a higher use of cash compared with the second quarter of 2005. The change
in non-cash working capital mainly related to a reduction of $108 million
in outstanding accounts receivable that had been sold under our
securitization program. The debt issuances and repayments presented in the
Consolidated Statements of Cash Flows include multiple drawings and
repayments under revolving debt facilities.
5.3 INVESTING ACTIVITIES
In the second quarter of 2006, cash used in investing activities
amounted to $773 million compared with $585 million in the second quarter
of 2005. Cash was used primarily for capital expenditures and provisions
for turnarounds partially offset by proceeds from asset sales.
5.4 SOURCES OF CAPITAL
Liquidity describes a company's ability to access cash. Companies
operating in the upstream oil and gas industry require sufficient cash to
fund capital programs necessary to maintain and increase production and
proved developed reserves, to acquire strategic oil and gas assets, repay
maturing debt and pay dividends. Husky's upstream capital programs are
funded principally by cash provided from operating activities. During times
of low oil and gas prices, part of a capital program can generally be
deferred. However, due to the long cycle times and the importance to future
cash flow in maintaining our production, it may be necessary to utilize
alternative sources of capital to continue our strategic investment plan
during periods of low commodity prices. As a result we continually examine
our options with respect to sources of long and short-term capital
resources. In addition, from time to time we engage in hedging a portion of
our revenue to protect cash flow.
-------------------------------------------------------------------------
Sources and Uses of Cash Six months Year ended
ended June 30 December 31
(millions of dollars) 2006 2005
-------------------------------------------------------------------------
Cash sourced
Cash flow from operations(1) $ 2,070 $ 3,785
Asset sales 33 74
Proceeds from exercise of stock options 1 6
Proceeds from monetization of financial
instruments - 39
-------------------------------------------------------------------------
2,104 3,904
-------------------------------------------------------------------------
Cash used
Capital expenditures 1,543 3,068
Debt repayment - net 96 215
Special dividend on common shares - 424
Ordinary dividends on common shares 212 276
Settlement of asset retirement obligations 14 41
Other 13 32
-------------------------------------------------------------------------
1,878 4,056
-------------------------------------------------------------------------
Net cash (deficiency) 226 (152)
Increase (decrease) in non-cash working
capital (281) 394
-------------------------------------------------------------------------
Increase (decrease) in cash and cash
equivalents (55) 242
Cash and cash equivalents - beginning of period 249 7
-------------------------------------------------------------------------
Cash and cash equivalents - end of period $ 194 $ 249
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Cash flow from operations represents net earnings plus items not
affecting cash, which include accretion, depletion, depreciation and
amortization, future income taxes and foreign exchange.
Working capital is the amount by which current assets exceed current
liabilities. At June 30, 2006, our working capital deficiency was $854
million compared with $1.0 billion at December 31, 2005. These working
capital deficits are primarily the result of accounts payable related to
capital expenditures for exploration and development. Settlement of these
current liabilities is funded by cash provided by operating activities and
to the extent necessary by bank borrowings. This position is a common
characteristic of the oil and gas industry which, by the nature of its
business, spends large amounts of capital.
At June 30, 2006, we had unused committed long and short-term credit
facilities totalling $1.4 billion. A total of $12 million of our borrowing
credit facilities were used in support of outstanding letters of credit and
an additional $54 million of letters of credit were outstanding at June 30,
2006 and supported by dedicated credit lines. During the second quarter of
2006 our long-term revolving credit facilities were extended from three to
five year maturities.
Credit Ratings
During the second quarter, Standard & Poor's Ratings Services placed
the Company's long-term corporate credit and senior unsecured debt ratings
on CreditWatch with positive implications. As at June 30, 2006 the
Company's senior unsecured debt was rated Baa2 by Moody's Investors
Service, BBB by Standard & Poor's Ratings Services, BBB (high) by Dominion
Bond Rating Service and BBB+ by Fitch Ratings.
-------------------------------------------------------------------------
Financial Ratios Three months Six months
ended June 30 ended June 30
(millions of dollars,
except ratios) 2006 2005 2006 2005
-------------------------------------------------------------------------
Cash flow
- operating
activities $ 1,302 $ 771 $ 2,426 $ 1,500
- financing
activities $ (339) $ (192) $ (848) $ (253)
- investing
activities $ (773) $ (585) $ (1,633) $ (1,251)
Debt to capital
employed (percent) 16.3 24.5
Corporate
reinvestment
ratio(1)(2) 0.8 1.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Calculated for the 12 months ended for the periods shown.
(2) Reinvestment ratio is based on net capital expenditures including
corporate acquisitions.
5.5 CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
Refer to Husky's 2005 annual Management's Discussion and Analysis under
the caption "Cash Requirements" which summarizes contractual obligations
and commercial commitments. There has been no material change in these
amounts as at June 30, 2006.
5.6 OFF BALANCE SHEET ARRANGEMENTS
We do not utilize off balance sheet arrangements with unconsolidated
entities to enhance perceived liquidity.
We engage, in the ordinary course of business, in the securitization of
accounts receivable. At June 30, 2006, we had sold $242 million of accounts
receivable under the securitization program. The securitization program
permits the sale of a maximum $350 million of accounts receivable on a
revolving basis. The accounts receivable are sold to an unrelated third
party and in accordance with the agreement we must provide a loss reserve
to replace defaulted receivables. The securitization agreement expires on
January 31, 2009.
The securitization program provides us with cost effective short-term
funding for general corporate use. We account for these securitizations as
asset sales. In the event the program is terminated our liquidity would not
be materially reduced.
6.0 TRANSACTIONS WITH RELATED PARTIES
We did not have any significant transactions with related parties
during the first six months of 2006 or during the year ended December 31,
2005.
7.0 SIGNIFICANT CUSTOMERS
We did not have any customers that constituted more than 10 percent of
total sales and operating revenues during the first six months of 2006.
8.0 FINANCIAL AND DERIVATIVE INSTRUMENTS
Husky is exposed to market risks related to commodity prices, interest
rates and foreign exchange rates as discussed under Section 3.0 "Business
Environment". From time to time, we use financial and derivative
instruments to manage our exposure to these risks.
8.1 POWER CONSUMPTION
At June 30, 2006, we had hedged power consumption as follows:
-------------------------------------------------------------------------
(millions of dollars, Notional
except where Volumes Unrecognized
indicated) (MW) Term Price Gain (Loss)
-------------------------------------------------------------------------
Fixed price purchase 19.0 July to $ 62.50/MWh $ -
Aug. 2006
19.0 July to $ 63.00/MWh (0.1)
Sept. 2006
38.0 Oct. to $ 62.95/MWh 0.3
Dec. 2006
-------------------------------------------------------------------------
$ 0.2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
8.2 INTEREST RATE RISK MANAGEMENT
In the first six months of 2006, interest rate risk management
activities resulted in a decrease to interest expense of $1 million.
The cross currency swaps resulted in an addition to interest expense of
$5 million in the first six months of 2006.
Husky has interest rate swaps on $200 million of long-term debt
effective February 8, 2002 whereby 6.95 percent was swapped for CDOR + 175
bps until July 14, 2009. During the first six months of 2006, 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 $5 million offset to interest expense in the first six
months of 2006.
8.3 FOREIGN CURRENCY RISK MANAGEMENT
Please refer to note 11 of the Consolidated Financial Statements.
9.0 APPLICATION OF CRITICAL ACCOUNTING ESTIMATES
Certain of our accounting policies require that we make appropriate
decisions with respect to the formulation of estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses.
For a discussion about those accounting policies, please refer to our
Management's Discussion and Analysis for the year ended December 31, 2005
available at http://www.sedar.com.
10.0 NEW ACCOUNTING STANDARDS
Effective January 1, 2006, we adopted the revised recommendations of
the Canadian Institute of Chartered Accountants section 3831, "Non-monetary
Transactions" which replaced section 3830 of the same name. The new
recommendations require that all non-monetary transactions are measured
based on fair value unless the transaction lacks commercial substance or is
an exchange of product or property held for sale in the ordinary course of
business. The guidance was effective for all non-monetary transactions
initiated in periods beginning on or after January 1, 2006.
11.0 OUTSTANDING SHARE DATA
-------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31
(in thousands, except per share amounts) 2006 2005
-------------------------------------------------------------------------
Share price(1)
High $ 75.64 $ 69.95
Low $ 58.00 $ 32.30
Close at end of period $ 70.06 $ 59.00
Average daily trading volume 624 664
Weighted average number of common shares
outstanding
Basic 424,163 423,964
Diluted 424,163 423,964
Issued and outstanding at end of period(2)
Number of common shares 424,187 424,125
Number of stock options 6,783 7,285
Number of stock options exercisable 3,145 1,533
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Trading in the common shares of Husky Energy Inc. ("HSE") commenced
on the Toronto Stock Exchange on August 28, 2000. The Company is
represented in the S&P/TSX Composite, S&P/TSX Canadian Energy Sector
and in the S&P/TSX 60 indices.
(2) There were no significant issuances of common shares, stock options
or any other securities convertible into, or exercisable or
exchangeable for common shares during the period from June 30, 2006
to July 11, 2006.
12.0 NON-GAAP MEASURES
Disclosure of Cash Flow from Operations
Management's Discussion and Analysis contains the term "cash flow from
operations", which should not be considered an alternative to, or more
meaningful than "cash flow - operating activities" as determined in
accordance with generally accepted accounting principles as an indicator of
our financial performance. Our determination of cash flow from operations
may not be comparable to that reported by other companies. Cash flow from
operations equals net earnings plus items not affecting cash which include
accretion, depletion, depreciation and amortization, future income taxes,
foreign exchange and other non-cash items.
The following table shows the reconciliation of cash flow from
operations to cash flow - operating activities for the periods noted:
-------------------------------------------------------------------------
Six months Year ended
ended June 30 December 31
(millions of dollars) 2006 2005
-------------------------------------------------------------------------
Non-GAAP
Cash flow from operations $ 2,070 $ 3,785
Settlement of asset retirement obligations (14) (41)
Change in non-cash working capital 370 (72)
-------------------------------------------------------------------------
GAAP
Cash flow - operating activities $ 2,426 $ 3,672
-------------------------------------------------------------------------
-------------------------------------------------------------------------
13.0 TERMS AND ABBREVIATIONS
bbls barrels
bps basis points
mbbls thousand barrels
mbbls/day thousand barrels per day
mmbbls million barrels
mcf thousand cubic feet
mmcf million cubic feet
mmcf/day million cubic feet per day
bcf billion cubic feet
tcf trillion cubic feet
boe barrels of oil equivalent
mboe thousand barrels of oil equivalent
mboe/day thousand barrels of oil equivalent per day
mmboe million barrels of oil equivalent
mcfge thousand cubic feet of gas equivalent
GJ gigajoule
mmbtu million British Thermal Units
mmlt million long tons
MW megawatt
MWh megawatt hour
NGL natural gas liquids
WTI West Texas Intermediate
NYMEX New York Mercantile Exchange
NIT NOVA Inventory Transfer(1)
LIBOR London Interbank Offered Rate
CDOR Certificate of Deposit Offered Rate
SEDAR System for Electronic Document Analysis and
Retrieval
FPSO Floating production, storage and offloading
vessel
OPEC Organization of Petroleum Exporting Countries
WCSB Western Canada Sedimentary Basin
SAGD Steam-assisted gravity drainage
Capital Employed Short- and long-term debt and shareholders'
equity
Capital Expenditures Includes capitalized administrative expenses
and capitalized interest but does not
include proceeds or other assets
Cash Flow from Operations Earnings from operations plus non-cash
charges before settlement of asset
retirement obligations and change in
non-cash working capital
Equity Shares and retained earnings
Total Debt Long-term debt including current portion and
bank operating loans
hectare One hectare is equal to 2.47 acres
initial reserves Remaining reserves plus cumulative production
feedstock Raw materials which are processed into
petroleum products
design rate capacity The maximum continuous rated output of a
plant based on its design
(1) NOVA Inventory Transfer is an exchange or transfer of title of gas
that has been received into the NOVA pipeline system but not yet
delivered to a connecting pipeline.
Natural gas converted on the basis that six mcf equals one barrel of oil.
In this report, the terms "Husky Energy Inc.", "Husky", "we", "our" or
"the Company" mean Husky Energy Inc. and its subsidiaries and partnership
interests on a consolidated basis.
14.0 FORWARD-LOOKING STATEMENTS OR INFORMATION
Certain statements in this Interim Report are forward-looking
statements or information (collectively "forward-looking statements"),
within the meaning of the applicable Canadian securities legislation, and
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 forward-looking statements made in this
Interim Report. Any statements that express, or involve discussions as to
expectations, beliefs, plans, objectives, assumptions or future events or
performance (often, but not always, through the use of words or phrases
such as "will likely result," "are expected to," "will continue," "is
anticipated," "estimated," "intend," "plan," "projection," "could,"
"vision," "goals," "objective" and "outlook") are not historical facts and
may be forward-looking and may involve estimates, assumptions and
uncertainties which could cause actual results or outcomes to differ
materially from those expressed in the forward-looking statements. In
particular, forward-looking statements and information include: our steam
injection and production plans for the Tucker in-situ oil sands project,
our White Rose drilling, development and production plans, our West Bonne
Bay drilling plans, our Lloydminster ethanol plant production plans, our
Minnedosa ethanol plant commissioning plans, our throughput capacity
projections for the ethanol plants, our East Coast seismic program, our
Sunrise oil sands project design schedule, and water evaluation and
stratigraphic drilling plans, our South China Sea drilling and seismic
evaluation plans, our East China Sea drilling plans, and our Lloydminster
Upgrader expansion design plans. Accordingly, any such forward-looking
statements are qualified in their entirety by reference to, and are
accompanied by, the factors discussed throughout this Interim Report. Among
the key factors that have a direct bearing on the Company's results of
operations are the nature of the Company's involvement in the business of
exploration, development and production of oil and natural gas reserves and
the fluctuation of the exchange rate between the Canadian dollar and the
United States dollar. These and other factors are discussed herein under
"Management's Discussion and Analysis".
ADD: /FIRST AND FINAL ADD - TO318 - Husky Energy Inc./
Because actual results or outcomes could differ materially from those
expressed in any forward-looking statements of the Company made by or on behalf
of the Company, 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:
- fluctuations in commodity prices;
- the accuracy of our oil and gas reserve estimates and estimated
production levels as they are affected by our success at exploration
and development drilling and related activities and estimated decline
rates;
- the uncertainties resulting from potential delays or changes in plans
with respect to exploration or development projects or capital
expenditures;
- changes in general economic, market and business conditions;
- fluctuations in supply and demand for our products;
- fluctuations in the cost of borrowing;
- our use of derivative financial instruments to hedge exposure to
changes in commodity prices and fluctuations in interest rates and
foreign currency exchange rates;
- political and economic developments, expropriations, royalty and tax
increases, retroactive tax claims and changes to import and export
regulations and other foreign laws and policies in the countries in
which we operate;
- our ability to receive timely regulatory approvals;
- the integrity and reliability of our capital assets;
- the cumulative impact of other resource development projects;
- the maintenance of satisfactory relationships with unions, employee
associations and joint venturers;
- competitive actions of other companies, including increased
competition from other oil and gas companies or from companies that
provide alternate sources of energy;
- actions by governmental authorities, including changes in
environmental and other regulations that may impose restrictions in
areas where we operate;
- the ability and willingness of parties with whom we have material
relationships to fulfill their obligations; and
- the occurrence of unexpected events such as fires, blowouts, freeze-
ups, equipment failures and other similar events affecting us or
other parties whose operations or assets directly or indirectly
affect us and that may or may not be financially recoverable.
Further, any forward-looking statement speaks only as of the date on
which such statement is made, and, except as required by applicable
securities laws, the Company undertakes no obligation to update any
forward-looking statement or statements 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
statements.
15.0 CAUTIONARY NOTE REQUIRED BY NATIONAL INSTRUMENT 51-101
The Company uses the terms barrels of oil equivalent ("boe") and
thousand cubic feet of gas equivalent ("mcfge"), which are calculated on an
energy equivalence basis whereby one barrel of crude oil is equivalent to
six thousand cubic feet of natural gas. Readers are cautioned that the
terms boe and mcfge may be misleading, particularly if used in isolation.
This measure is primarily applicable at the burner tip and does not
represent value equivalence at the well head.
Husky's disclosure of reserves data and other oil and gas information
is made in reliance on an exemption granted to Husky by Canadian securities
regulatory authorities, which permits Husky to provide disclosure required
by and consistent with those of the United States Securities and Exchange
Commission and the Financial Accounting Standards Board in the United
States in place of much of the disclosure expected by National Instrument
51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer
to "Disclosure of Exemption Under National Instrument 51-101" at page 2 of
our Annual Information Form for the year ended December 31, 2005 filed with
securities regulatory authorities for further information.
16.0 CAUTIONARY NOTE TO U.S. INVESTORS
The United States Securities and Exchange Commission permits oil and
gas companies, in their filings with the SEC, to disclose only proved
reserves that a company has demonstrated with actual production or
conclusive formation tests to be economically and legally producible under
existing economic and operating conditions. We use certain terms in this
release and Interim Report, such as "probable reserves" and "recoverable
resource", that the SEC's guidelines strictly prohibit us from including in
filings with the SEC. U.S. investors should refer to our Annual Report on
Form 40-F available from us or the SEC for further reserve disclosure.
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
-------------------------------------------------------------------------
June 30 December 31
(millions of dollars) 2006 2005
-------------------------------------------------------------------------
(unaudited) (audited)
Assets
Current assets
Cash and cash equivalents $ 194 $ 249
Accounts receivable 747 856
Inventories 465 471
Prepaid expenses 70 40
-------------------------------------------------------------------------
1,476 1,616
Property, plant and equipment - (full cost
accounting) 23,881 22,375
Less accumulated depletion, depreciation
and amortization 9,166 8,416
-------------------------------------------------------------------------
14,715 13,959
Goodwill 160 160
Other assets 54 62
-------------------------------------------------------------------------
$ 16,405 $ 15,797
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 2,063 $ 2,391
Long-term debt due within one year (note 5) 267 274
-------------------------------------------------------------------------
2,330 2,665
Long-term debt (note 5) 1,455 1,612
Other long-term liabilities (note 6) 717 730
Future income taxes 3,089 3,270
Commitments and contingencies (note 8)
Shareholders' equity
Common shares (note 9) 3,527 3,523
Retained earnings 5,287 3,997
-------------------------------------------------------------------------
8,814 7,520
-------------------------------------------------------------------------
$ 16,405 $ 15,797
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common shares outstanding (millions) (note 9) 424.2 424.1
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Consolidated Statements of Earnings
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
(millions of dollars,
except per share
amounts) (unaudited) 2006 2005 2006 2005
-------------------------------------------------------------------------
Sales and operating
revenues, net of
royalties $ 3,040 $ 2,350 $ 6,144 $ 4,444
Costs and expenses
Cost of sales and
operating expenses 1,638 1,331 3,465 2,482
Selling and
administration
expenses 50 40 77 69
Stock-based
compensation 15 77 85 98
Depletion,
depreciation and
amortization 383 304 762 602
Interest - net
(note 5) 22 6 49 16
Foreign exchange
(note 5) (32) 20 (37) 27
Other - net 5 2 8 5
-------------------------------------------------------------------------
2,081 1,780 4,409 3,299
-------------------------------------------------------------------------
Earnings before
income taxes 959 570 1,735 1,145
-------------------------------------------------------------------------
Income taxes (note 7)
Current 210 75 414 142
Future (229) 101 (181) 225
-------------------------------------------------------------------------
(19) 176 233 367
-------------------------------------------------------------------------
Net earnings $ 978 $ 394 $ 1,502 $ 778
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings per share
Basic $ 2.31 $ 0.93 $ 3.54 $ 1.84
Diluted $ 2.31 $ 0.93 $ 3.54 $ 1.84
Weighted average
number of common
shares outstanding
(millions)
Basic 424.2 423.9 424.2 423.8
Diluted 424.2 423.9 424.2 423.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Consolidated Statements of Retained Earnings
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
(millions of dollars)
(unaudited) 2006 2005 2006 2005
-------------------------------------------------------------------------
Beginning of period $ 4,415 $ 3,027 $ 3,997 $ 2,694
Net earnings 978 394 1,502 778
Dividends on common
shares (106) (59) (212) (110)
-------------------------------------------------------------------------
End of period $ 5,287 $ 3,362 $ 5,287 $ 3,362
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Consolidated Statements of Cash Flows
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
(millions of dollars)
(unaudited) 2006 2005 2006 2005
-------------------------------------------------------------------------
Operating activities
Net earnings $ 978 $ 394 $ 1,502 $ 778
Items not affecting
cash
Accretion (note 6) 9 9 18 17
Depletion,
depreciation and
amortization 383 304 762 602
Future income
taxes (note 7) (229) 101 (181) 225
Foreign exchange (41) 17 (42) 24
Other 3 3 11 (2)
Settlement of asset
retirement
obligations (6) (9) (14) (14)
Change in non-cash
working capital
(note 4) 205 (48) 370 (130)
-------------------------------------------------------------------------
Cash flow
- operating
activities 1,302 771 2,426 1,500
-------------------------------------------------------------------------
Financing activities
Bank operating
loans financing
- net (62) (48) - (15)
Long-term debt
issue 251 1,029 1,226 2,451
Long-term debt
repayment (300) (1,150) (1,322) (2,393)
Proceeds from
exercise of stock
options - 3 1 4
Proceeds from
monetization of
financial
instruments - 30 - 30
Dividends on common
shares (106) (59) (212) (110)
Change in non-cash
working capital
(note 4) (122) 3 (541) (220)
-------------------------------------------------------------------------
Cash flow
- financing
activities (339) (192) (848) (253)
-------------------------------------------------------------------------
Available for investing 963 579 1,578 1,247
-------------------------------------------------------------------------
Investing activities
Capital expenditures (683) (613) (1,543) (1,304)
Asset sales 1 14 33 57
Other (12) (2) (13) (2)
Change in non-cash
working capital
(note 4) (79) 16 (110) (2)
-------------------------------------------------------------------------
Cash flow - investing
activities (773) (585) (1,633) (1,251)
-------------------------------------------------------------------------
Increase (decrease) in
cash and cash
equivalents 190 (6) (55) (4)
Cash and cash
equivalents at
beginning of period 4 9 249 7
-------------------------------------------------------------------------
Cash and cash
equivalents at end
of period $ 194 $ 3 $ 194 $ 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Notes to the Consolidated Financial Statements
Six months ended June 30, 2006 (unaudited)
Except where indicated and per share amounts, all dollar amounts are in
millions.
Note 1 Segmented Financial Information
-------------------------------------------------------------------------
Upstream Midstream
Infrastructure
Upgrading and Marketing
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Three months
ended June 30
Sales and
operating
revenues, net
of royalties $ 1,451 $ 976 $ 404 $ 393 $ 2,267 $ 1,611
Costs and
expenses
Operating,
cost of
sales,
selling and
general 308 249 319 249 2,190 1,552
Depletion,
depreciation
and
amortization 354 278 6 4 5 6
Interest
- net - - - - - -
Foreign
exchange - - - - - -
-------------------------------------------------------------------------
662 527 325 253 2,195 1,558
-------------------------------------------------------------------------
Earnings (loss)
before income
taxes 789 449 79 140 72 53
Current
income
taxes 156 69 29 (2) 20 (4)
Future
income
taxes (189) 73 (29) 45 (9) 24
-------------------------------------------------------------------------
Net earnings
(loss) $ 822 $ 307 $ 79 $ 97 $ 61 $ 33
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital
expenditures
- Three
months ended
June 30 $ 554 $ 536 $ 38 $ 30 $ 11 $ 7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months
ended June 30
Sales and
operating
revenues, net
of royalties $ 2,738 $ 1,864 $ 809 $ 746 $ 4,731 $ 3,063
Costs and
expenses
Operating,
cost of
sales,
selling
and general 619 489 581 444 4,562 2,905
Depletion,
depreciation
and
amortization 705 551 12 9 11 11
Interest
- net - - - - - -
Foreign
exchange - - - - - -
-------------------------------------------------------------------------
1,324 1,040 593 453 4,573 2,916
-------------------------------------------------------------------------
Earnings (loss)
before income
taxes 1,414 824 216 293 158 147
Current
income taxes 299 122 53 9 39 (11)
Future income
taxes (119) 156 (9) 80 1 63
-------------------------------------------------------------------------
Net earnings
(loss) $ 1,234 $ 546 $ 172 $ 204 $ 118 $ 95
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital
employed - As
at June 30 $ 9,400 $ 7,878 $ 538 $ 490 $ 311 $ 570
Capital
expenditures
- Six months
ended
June 30 $ 1,311 $ 1,198 $ 75 $ 47 $ 12 $ 13
Total assets
- As at
June 30 $13,436 $11,575 $ 912 $ 751 $ 718 $ 871
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Corporate and
Refined Products Eliminations(1) Total
2006 2005 2006 2005 2006 2005
-------------------------------------------------------------------------
Three months
ended June 30
Sales and
operating
revenues, net
of royalties $ 674 $ 560 $(1,756) $(1,190) $ 3,040 $ 2,350
Costs and
expenses
Operating,
cost of
sales,
selling and
general 596 518 (1,705) (1,118) 1,708 1,450
Depletion,
depreciation
and
amortization 13 11 5 5 383 304
Interest
- net - - 22 6 22 6
Foreign
exchange - - (32) 20 (32) 20
-------------------------------------------------------------------------
609 529 (1,710) (1,087) 2,081 1,780
-------------------------------------------------------------------------
Earnings (loss)
before income
taxes 65 31 (46) (103) 959 570
Current
income
taxes 3 (1) 2 13 210 75
Future
income
taxes 10 12 (12) (53) (229) 101
-------------------------------------------------------------------------
Net earnings
(loss) $ 52 $ 20 $ (36) $ (63) $ 978 $ 394
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital
expenditures
- Three
months ended
June 30 $ 79 $ 43 $ 7 $ 4 $ 689 $ 620
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months
ended June 30
Sales and
operating
revenues, net
of royalties $ 1,220 $ 997 $(3,354) $(2,226) $ 6,144 $ 4,444
Costs and
expenses
Operating,
cost of
sales,
selling
and general 1,107 917 (3,234) (2,101) 3,635 2,654
Depletion,
depreciation
and
amortization 23 20 11 11 762 602
Interest
- net - - 49 16 49 16
Foreign
exchange - - (37) 27 (37) 27
-------------------------------------------------------------------------
1,130 937 (3,211) (2,047) 4,409 3,299
-------------------------------------------------------------------------
Earnings (loss)
before income
taxes 90 60 (143) (179) 1,735 1,145
Current
income taxes 12 (2) 11 24 414 142
Future income
taxes 10 24 (64) (98) (181) 225
-------------------------------------------------------------------------
Net earnings
(loss) $ 68 $ 38 $ (90) $ (105) $ 1,502 $ 778
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Capital
employed - As
at June 30 $ 577 $ 399 $ (290) $ (234) $10,536 $ 9,103
Capital
expenditures
- Six months
ended
June 30 $ 143 $ 48 $ 13 $ 8 $ 1,554 $ 1,314
Total assets
- As at
June 30 $ 1,005 $ 727 $ 334 $ 134 $16,405 $14,058
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Eliminations relate to sales and operating revenues between segments
recorded at transfer prices based on current market prices, and to
unrealized intersegment profits in inventories.
Note 2 Significant Accounting Policies
The interim consolidated financial statements of Husky Energy Inc.
("Husky" or "the Company") have been prepared by management in accordance
with accounting principles generally accepted in Canada. The interim
consolidated financial statements have been prepared following the same
accounting policies and methods of computation as the consolidated
financial statements for the fiscal year ended December 31, 2005, except
as noted below. The interim consolidated financial statements should be
read in conjunction with the consolidated financial statements and the
notes thereto in the Company's annual report for the year ended
December 31, 2005.
Note 3 Change in Accounting Policies
Non-monetary Transactions
Effective January 1, 2006, the Company adopted the revised
recommendations of the Canadian Institute of Chartered Accountants
section 3831, "Non-monetary Transactions" which replaced section 3830 of
the same name. The new recommendations require that all non-monetary
transactions are measured based on fair value unless the transaction
lacks commercial substance or is an exchange of product or property held
for sale in the ordinary course of business. The guidance was effective
for all non-monetary transactions initiated in periods beginning on or
after January 1, 2006.
Note 4 Cash Flows - Change in Non-cash Working Capital
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
a) Change in non-cash
working capital
was as follows:
Decrease (increase)
in non-cash
working capital
Accounts
receivable $ 5 $ 25 $ 109 $ (20)
Inventories (26) (86) 6 (140)
Prepaid expenses (23) (7) (19) (18)
Accounts payable
and accrued
liabilities 48 39 (377) (174)
-------------------------------------------------------------------------
Change in non-cash
working capital 4 (29) (281) (352)
Relating to:
Financing
activities (122) 3 (541) (220)
Investing
activities (79) 16 (110) (2)
-------------------------------------------------------------------------
Operating
activities $ 205 $ (48) $ 370 $ (130)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
b) Other cash flow
information:
Cash taxes paid $ 44 $ 76 $ 173 $ 159
Cash interest
paid $ 47 $ 43 $ 79 $ 73
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note 5 Long-term Debt
-------------------------------------------------------------------------
June 30 Dec 31 June 30 Dec 31
Maturity 2006 2005 2006 2005
-------------------------------------------------------------------------
Cdn $ Amount U.S. $ Denominated
Long-term debt
7.125% notes 2006 $ 167 $ 175 $ 150 $ 150
6.25% notes 2012 446 467 400 400
7.55%
debentures 2016 223 233 200 200
6.15% notes 2019 335 350 300 300
8.45% senior
secured
bonds - 99 - 85
Medium-term
notes 2007-9 300 300 - -
8.90%
capital
securities 2028 251 262 225 225
-------------------------------------------------------------------------
Total
long-term
debt 1,722 1,886 $ 1,275 $ 1,360
--------------------------
--------------------------
Amount due
within
one year (267) (274)
-----------------------------------------------
$ 1,455 $ 1,612
-----------------------------------------------
-----------------------------------------------
Interest - net consisted of:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Long-term debt $ 31 $ 36 $ 68 $ 70
Short-term debt 2 1 3 2
-------------------------------------------------------------------------
33 37 71 72
Amount capitalized (10) (31) (21) (55)
-------------------------------------------------------------------------
23 6 50 17
Interest income (1) - (1) (1)
-------------------------------------------------------------------------
$ 22 $ 6 $ 49 $ 16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Foreign exchange
consisted of:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
(Gain) loss on
translation of U.S.
dollar denominated
long-term debt $ (66) $ 22 $ (67) $ 31
Cross currency swaps 27 (4) 26 (6)
Other losses 7 2 4 2
-------------------------------------------------------------------------
$ (32) $ 20 $ (37) $ 27
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note 6 Other Long-term Liabilities
Asset Retirement Obligations
Changes to asset retirement obligations were as
follows:
-------------------------------------------------------------------------
Six months
ended June 30
2006 2005
-------------------------------------------------------------------------
Asset retirement obligations at beginning of
period $ 557 $ 509
Liabilities incurred 10 8
Liabilities disposed - (7)
Liabilities settled (14) (14)
Accretion 18 17
-------------------------------------------------------------------------
Asset retirement obligations at end of period $ 571 $ 513
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2006, the estimated total undiscounted inflation adjusted
amount required to settle the asset retirement obligations was
$3.4 billion. These obligations will be settled based on the useful lives
of the underlying assets, which currently extend up to 50 years into the
future. This amount has been discounted using credit adjusted risk free
rates ranging from 6.2 to 6.4 percent.
Note 7 Income Taxes
The recovery of future taxes in the second quarter of 2006 resulted from
recording non-recurring tax benefits of $328 million that arose due to
changes in the tax rates for the governments of Canada ($198 million),
Alberta ($90 million) and Saskatchewan ($40 million). All of this tax
legislation received royal assent and was, therefore, substantively
enacted in the second quarter of 2006. There were no similar tax rate
benefits recorded in the first quarter of 2006 or during the first six
months of 2005.
Note 8 Commitments and Contingencies
The Company has no material litigation other than various claims and
litigation arising in the normal course of business. While the outcome of
these matters is uncertain and there can be no assurance that such
matters will be resolved in the Company's favour, the Company does not
currently believe that the outcome of adverse decisions in any pending or
threatened proceedings related to these and other matters or any amount
which it may be required to pay by reason thereof would have a material
adverse impact on its financial position, results of operations or
liquidity.
Note 9 Share Capital
The Company's authorized share capital consists of an unlimited number of
no par value common and preferred shares.
Common Shares
Changes to issued common shares were as follows:
-------------------------------------------------------------------------
Six months ended June 30
2006 2005
-------------------------------------------------------------------------
Number of Number of
Shares Amount Shares Amount
-------------------------------------------------------------------------
Balance at beginning
of period 424,125,078 $ 3,523 423,736,414 $ 3,506
Exercised - options
and warrants 62,265 4 246,341 9
-------------------------------------------------------------------------
Balance at June 30 424,187,343 $ 3,527 423,982,755 $ 3,515
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Stock Options
A summary of the status of the Company's stock option plan is presented
below:
-------------------------------------------------------------------------
Six months ended June 30
2006 2005
-------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Options Exercise
(thousands) Prices (thousands) Prices
-------------------------------------------------------------------------
Outstanding, beginning
of period 7,285 $ 25.81 9,964 $ 22.61
Granted 567 $ 69.33 175 $ 35.29
Exercised for common
shares (62) $ 20.97 (217) $ 16.27
Surrendered for cash (834) $ 22.84 (1,646) $ 18.10
Forfeited (173) $ 40.18 (281) $ 24.46
-------------------------------------------------------------------------
Outstanding at June 30 6,783 $ 29.49 7,995 $ 23.92
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Options exercisable at
June 30 3,145 $ 23.59 2,281 $ 21.98
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
June 30, 2006
Outstanding Options Options Exercisable
-------------------------------------------------------------------------
Weighted Weighted Weighted
Range of Number of Average Average Number of Average
Exercise Options Exercise Contractual Options Exercise
Price (thousands) Prices Life (years) (thousands) Prices
-------------------------------------------------------------------------
$13.96
- $14.99 92 $ 14.56 2 92 $ 14.56
$15.00
- $22.99 173 $ 19.75 2 97 $ 18.78
$23.00
- $23.99 5,194 $ 23.83 3 2,876 $ 23.83
$24.00
- $39.99 352 $ 32.07 3 80 $ 31.39
$40.00
- $55.99 440 $ 51.96 4 - $ -
$56.00
- $73.80 532 $ 70.26 5 - $ -
-------------------------------------------------------------------------
6,783 $ 29.49 3 3,145 $ 23.59
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note 10 Employee Future Benefits
Total benefit costs recognized were as follows:
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2006 2005 2006 2005
-------------------------------------------------------------------------
Employer current
service cost $ 5 $ 5 $ 9 $ 9
Interest cost 3 3 5 5
Expected return on
plan assets (2) (2) (3) (4)
Amortization of net
actuarial losses - - - 1
-------------------------------------------------------------------------
$ 6 $ 6 $ 11 $ 11
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Note 11 Financial Instruments and Risk Management
Unrecognized gains (losses) on derivative instruments were as follows:
-------------------------------------------------------------------------
June 30 Dec. 31
2006 2005
-------------------------------------------------------------------------
Commodity price risk management
Power consumption $ - $ -
Interest rate risk management
Interest rate swaps 2 7
Foreign currency risk management
Foreign exchange contracts (27) (32)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commodity Price Risk Management
Power Consumption
At June 30, 2006, the Company had hedged power consumption as follows:
-------------------------------------------------------------------------
Notional
Volumes
(MW) Term Price
-------------------------------------------------------------------------
Fixed price purchase 19.0 July to Aug. 2006 $ 62.50/MWh
19.0 July to Sept. 2006 $ 63.00/MWh
38.0 Oct. to Dec. 2006 $ 62.95/MWh
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The impact of the hedge program during the first six months of 2006 was a
loss of $1.0 million (2005 - loss of $0.1 million).
Natural Gas Contracts
At June 30, 2006, the unrecognized gains (losses) on external offsetting
physical purchase and sale natural gas contracts were as follows:
-------------------------------------------------------------------------
Unrecog-
Volumes nized
(mmcf) Gain (Loss)
-------------------------------------------------------------------------
Physical purchase contracts 32,747 $ (1)
Physical sale contracts (32,747) $ 5
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest Rate Risk Management
During the first six months of 2006, the Company realized a gain of
$1 million (2005 - gain of $9 million) from interest rate risk management
activities.
Foreign Currency Risk Management
During the first six months of 2006, the Company realized a loss of
$21 million (2005 - gain of $7 million) from all foreign currency risk
management activities.
Sale of Accounts Receivable
The Company has a securitization program to sell, on a revolving basis,
accounts receivable to a third party up to $350 million. As at June 30,
2006, $242 million in outstanding accounts receivable had been sold under
the program, a reduction of $108 million in the second quarter compared
with $350 million in outstanding account receivable sold at December 31,
2005. In July 2006, the program to sell accounts receivable was further
reduced by $17 million to $225 million.
Husky Energy will release its second quarter financial results after
markets close on Wednesday, July 19, 2006. A conference call for analysts
and investors will be held on Thursday, July 20, 2006 at 4:15 p.m. (EST).
Mr. John C.S. Lau, President & Chief Executive Officer and other
officers will be participating in the call.
Media are invited to listen to the conference call by dialing
1-800-377- 5794 beginning at 4:05 p.m. (EST). Those unable to listen to the
call live may listen to a recording by dialing 1-800-558-5253 one hour
after the completion of the call, approximately 6:15 p.m. (EST), then
dialing reservation number 21298690. The PostView will be available until
Thursday, August 17, 2006.
Husky Energy is a Canadian based, integrated energy and energy-related
company headquartered in Calgary, Alberta. Husky Energy is publicly traded
on the Toronto Stock Exchange under the symbol HSE.
SOURCE Husky Energy Inc.
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CONTACT:
Investor Relations, Colin Luciuk, Manager,
Investor Relations & Corporate Communications, Husky Energy Inc.,
(403) 750-4938; Tanis Thacker, Senior Analyst, Investor
Relations, Husky Energy Inc., (403) 298-6747; 707 - 8th Avenue
S.W., Box 6525, Station D, Calgary, Alberta, Canada T2P 3G7
Telephone: (403) 298-6111 Facsimile: (403) 298-6515 Website:
http://www.huskyenergy.ca e-mail: Investor.Relations@huskyenergy.ca/
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