CALGARY, Aug. 1 /PRNewswire-FirstCall/ - Husky Energy Inc. ("Husky")
today reported net earnings of $263 million ($0.64 per share) in the second
quarter of 2002, compared to $299 million ($0.73 per share) in the same
quarter of 2001. Cash flow from operations in the second quarter of 2002 was
$498 million ($1.17 per share) compared to $561 million ($1.32 per share) in
the same quarter of 2001. Net earnings rose 109 percent and cash flow rose 34
percent compared to the first quarter of 2002. Net earnings of $254 million
for the second quarter of 2001 have been restated to $299 million to reflect
adoption of the recommendations of the Canadian Institute of Chartered
Accountants on foreign currency translation.
Net earnings in the second quarter of 2002 were down from the same period
last year mainly due to lower natural gas prices, scheduled turnaround-related
throughput reductions at the Lloydminster Upgrader and lower marketing margins
in the refined products business. Net earnings were positively impacted by a
nine percent increase in production, which averaged 288,900 barrels of oil
equivalent per day in the second quarter compared to 264,000 barrels of oil
equivalent per day in the same quarter last year, higher prices on crude oil
production, a foreign exchange gain on the Company's U.S. dollar denominated
debt and a lower income tax provision.
"This was the first full quarter of production contribution from Terra
Nova," said Mr. John C.S. Lau, President and Chief Executive Officer of Husky.
"In addition, first oil was achieved at the Wenchang project in the South
China Sea in July which will add oil production and cash flow in the future.
We continue to make progress on the White Rose offshore project."
Husky's net earnings for the first six months of 2002 were $389 million
($0.93 per share), compared to $491 million ($1.15 per share) for the same
period in 2001. Cash flow from operations for the first six months of 2002 was
$871 million ($2.04 per share), compared to $1,181 million ($2.79 per share)
for the same period in 2001. Lower net earnings and cash flow reflect lower
natural gas prices, which were partially offset by higher crude oil prices.
First oil was achieved at the Wenchang offshore project on July 7, 2002.
Husky has a 40 percent working interest in Wenchang. The peak production is
expected to be 50,000 barrels of oil per day. The project is anticipated to
add an annual average 8,000 barrels of oil per day to Husky's production in
2002 and 20,000 barrels of oil per day when it reaches peak production.
Production from the Wenchang project has to-date exceeded expectations.
Lloydminster heavy crude oil production increased during the second
quarter of 2002 to an average of 76,900 barrels of oil per day from 60,300
barrels of oil per day in the same period in 2001 due to the 2001/2002
drilling program, well optimization program, higher cold production and the
acquisition of the Bolney/Celtic properties in the third quarter of 2001.
<<
Highlights
-------------------------------------------------------------------------
(millions of dollars, Three months ended Six months ended
except per share June 30 June 30
amounts) 2002 2001(1) %Change 2002 2001(1) %Change
-------------------------------------------------------------------------
Sales and operating
revenues, net of
royalties $ 1,659 $ 1,731 down 4 $ 3,018 $ 3,511 down 14
EBITDA(2) 599 647 down 7 1,030 1,229 down 16
Cash flow from
operations 498 561 down 11 871 1,181 down 26
Per share
- Basic 1.18 1.33 down 11 2.05 2.80 down 27
- Diluted 1.17 1.32 down 11 2.04 2.79 down 27
Operating profit
("EBIT") (3)
Upstream $ 262 $ 247 $ 421 $ 615
Midstream 46 128 133 234
Refined Products 22 44 32 54
Corporate and
eliminations (19) (18) (57) (39)
Foreign exchange 65 50 57 (23)
---------------- ----------------
Operating profit
("EBIT") 376 451 586 841
Interest - net (24) (26) (51) (54)
Income taxes (89) (126) (146) (296)
---------------- ----------------
Net earnings $ 263 $ 299 down 12 $ 389 $ 491 down 21
---------------- ----------------
---------------- ----------------
Per share
- Basic $ 0.64 $ 0.74 down 14 $ 0.93 $ 1.15 down 19
- Diluted 0.64 0.73 down 12 0.93 1.15 down 19
Dividend paid per
share 0.09 0.09 - 0.18 0.18 -
Daily production,
before royalties
Light/medium crude
oil & NGL (mbbls/day) 116.6 108.6 up 117.1 112.0 up 5
Lloydminster heavy
crude oil (mbbls/day) 76.9 60.3 up 28 76.9 58.6 up 31
Natural gas (mmcf/day) 571.8 570.8 - 569.0 577.4 down 1
Barrels of oil
equivalent (6:1)
(mboe/day) 288.9 264.0 up 9 288.8 266.8 up 8
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(1) 2001 amounts as restated. Refer to note 3 to the consolidated
financial statements.
(2) Earnings from operations before interest, income taxes and depletion,
depreciation and amortization. Refer to note 1 to the consolidated
financial statements for derivation of this number.
(3) Earnings from operations before interest and income taxes.
>>
Highlights
UPSTREAM
Production
Husky's production during the second quarter of 2002 averaged 289
mboe/day, an increase of nine percent over the second quarter of 2001. Higher
production of light/medium crude oil and NGL was due to production from the
Terra Nova oil field, which achieved first oil on January 20, 2002, which
offset lower production of light/medium crude oil and NGL from Western Canada.
Production from Terra Nova averaged 15 mbbls/day (net to Husky) during the
second quarter of 2002. Lloydminster heavy crude oil production increased by
28 percent in the second quarter of 2002 as a result of the 2001/2002 drilling
program, well optimization program, higher cold production and the acquisition
of the Bolney/Celtic properties in third quarter 2001. Natural gas production
increased marginally as new well tie-ins from the winter shallow gas program
in northwest Alberta offset natural declines. Light/medium crude oil
production from operations in Western Canada decreased during the second
quarter of 2002 compared with the second quarter of 2001 as a result of
natural declines, higher turnaround and maintenance activity and reduced
drilling and workovers as a result of an extended spring breakup.
Development drilling during the second quarter of 2002 resulted in 112
net oil wells (second quarter 2001 - 129 net wells) and 10 net natural gas
wells (second quarter 2001 - 17 net wells) in Western Canada with a success
rate of 95 percent.
Stage 1 of the Bolney/Celtic six mbbls/day heavy oil thermal expansion
project is progressing as planned with start-up scheduled for the fourth
quarter of 2002. The drilling of eight horizontal steam assisted gravity
drainage wells was completed and materials for a steam pipeline are on site.
Regulatory approvals have been received for Stage 1 and construction contracts
have been awarded.
Exploration
Western Canada
During the second quarter of 2002, 25 net exploratory wells were drilled
resulting in six net oil wells and 18 net natural gas wells, a 96 percent
success rate. Husky's exploration activity will be concentrated in the
winter-only access areas of northeast British Columbia, the foothills along
the eastern slopes of the Rocky Mountains and the Deep Basin portion of
Western Canada. Planning for the 2002/2003 winter exploration drilling
program is underway.
Trepassey
Husky announced in June that it was proceeding with its East Coast
exploration drilling program. Drilling on the Trepassey Exploration Licence
(EL 1044) in the Jeanne d'Arc Basin commenced in July, 2002. The exploration
well will test the oil potential of a large structure located approximately 10
kilometres south of the White Rose oil field and 350 kilometres east of
Newfoundland.
Major Project Update
East Coast, Canada
Terra Nova
Production from the Terra Nova oil field commenced in January, 2002.
Husky's share of production averaged more than 15 mbbls/day during the second
quarter. Husky has a 12.51 percent working interest in the project.
White Rose
Progress continues to be made on the White Rose Project. In April, the
Company announced it had awarded the contract to build the White Rose floating
production, storage and offloading ("FPSO") hull to Samsung Heavy Industries.
SBM IMODCO was awarded the contract for the design and fabrication of the
turret and mooring system for the FPSO. Aker Maritime Kiewit Contractors was
awarded the contract to design and build the topsides for the FPSO.
In June, the Company announced time charter contracts had been signed
with Knutsen OAS Shipping A.S. for two newbuild shuttle tankers to transport
oil from the White Rose FPSO to market. Each vessel will have a one million
barrel capacity.
International Offshore - China
Wenchang
First oil was achieved at the Wenchang development project in the South
China Sea on July 7, 2002. Husky has a 40 percent interest in the project. Oil
production at Wenchang is expected to average 20 mbbls/day (eight mbbls/day -
net to Husky) in 2002 and reach a peak of 50 mbbls/day (20 mbbls/day - net to
Husky) in 2003.
Oil Sands - Alberta
Kearl
Evaluation of the in-situ bitumen potential at Kearl is ongoing and
further stratigraphic test wells are planned for the 2002/2003 drilling
season. Work on site at Kearl was deferred during the second quarter due to a
forest fire and has now resumed. An environmental impact assessment will be
started in the third quarter of 2002.
Tucker
Development planning on the Tucker oil sands property commenced in the
second quarter of 2002. The public disclosure process will proceed in the
third quarter of 2002 followed by on site testing and detailed engineering
design.
MIDSTREAM
Second quarter 2002 sales of synthetic crude oil from the Lloydminster
Upgrader averaged 51.3 mbbls/day, as compared with 65.6 mbbls/day in the
second quarter of 2001. Lower production at the upgrader in the second
quarter of 2002 was due to a scheduled full plant turnaround. The upgrader
was shutdown for 16 days in June for this major maintenance program.
REFINED PRODUCTS
During the first half of 2002, sales of motor fuel per retail outlet
increased to average 8,100 litres per day from 7,400 litres per day in the
same period of 2001.
Forty-two Store Point systems were installed in the second quarter
bringing the total number of systems installed to ninety. Store Point is a
fully integrated point of sale system that includes scanning, pay at the pump
and integrated accounting functions.
During the second quarter of 2002, the first new Husky Market store was
commissioned. The Husky Market store model is designed to meet the challenges
evolving in the retail gasoline and convenience store industry. The new
outlets will present an appearance that is inviting, bright, clean and modern
combined with convenient layout and superior products and service. Husky plans
to rollout the Husky Market store model progressively over the next several
years.
Management's Discussion & Analysis
The following management's discussion and analysis should be read in
conjunction with the unaudited consolidated financial statements of the
Company for the six months ended June 30, 2002 and the audited consolidated
financial statements and management's discussion and analysis for the year
ended December 31, 2001, as restated. All dollar amounts are in millions of
Canadian dollars, unless otherwise indicated.
The calculation of barrels of oil equivalent ("boe") and thousands of
cubic feet equivalent ("mcfe") are based on a conversion rate of six thousand
cubic feet of natural gas for one barrel of crude oil. All comparisons refer
to the second quarter of 2002 compared with the second quarter of 2001 and the
first six months of 2002 compared with the first six months of 2001, unless
otherwise indicated.
Management's Discussion and Analysis contains certain terms such as
Earnings before interest, taxes, depletion, depreciation and amortization
("EBITDA"), Earnings before interest and taxes ("Operating profit" or "EBIT")
and cash flow from operations. These measurements should not be considered an
alternative to, or more meaningful than, net earnings or cash flow from
operating activities as determined in accordance with Canadian generally
accepted accounting principles ("GAAP") as indicators of the Company's
financial performance or liquidity. Husky's determination of EBITDA, EBIT and
cash flow from operations may not be comparable to those reported by other
companies. EBITDA, EBIT and cash flow from operations represent measurements
of financial performance to which each reporting business segment is
responsible. The other items required to arrive at net earnings or cash flow
are considered to be corporate in nature.
<<
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Quarterly Comparison (1)
-------------------------------------------------------------------------
Three months ended
June 30 March 31 Dec. 31 Sept. 30 June 30
2002 2002 2001 2001 2001
-------------------------------------------------------------------------
Sales and operating
revenues, net of
royalties $ 1,659 $ 1,359 $ 1,615 $ 1,470 $ 1,731
EBITDA 599 431 302 451 647
Cash flow from
operations 498 373 287 478 561
Per share
- Basic 1.18 0.88 0.67 1.13 1.33
- Diluted 1.17 0.87 0.66 1.12 1.32
Net earnings 263 126 45 118 299
Per share
- Basic 0.64 0.29 0.09 0.25 0.74
- Diluted 0.64 0.29 0.09 0.24 0.73
Daily production,
before royalties
Light/medium crude
oil & NGL
(mbbls/day) 116.6 117.5 111.3 112.7 108.6
Lloydminster heavy
crude oil
(mbbls/day) 76.9 76.9 75.0 69.1 60.3
Natural gas
(mmcf/day) 571.8 566.0 568.7 567.1 570.8
Barrels of oil
equivalent (6:1)
(mboe/day) 288.9 288.7 281.1 276.3 264.0
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2001 amounts as restated. Refer to note 3 to the consolidated
financial statements.
>>
Second quarter 2002 net earnings of $263 million ($0.64 per share - basic
& diluted) were 109 percent higher than the $126 million ($0.29 per share -
basic & diluted) reported for the first quarter of 2002. The higher earnings
were due to higher prices for crude oil, NGL, and natural gas, higher
upgrading differential, higher sales volume and margins for light oil refined
products and asphalt products, foreign exchange gains and lower interest
expense. These positive factors were partially offset by lower upgrader
throughput due to a 16 day scheduled turnaround, lower income from
infrastructure activities, higher depletion, depreciation and amortization
expense and higher income tax expense.
The upstream operations produced 289 mboe/day during the second quarter
of 2002, the same as in the first quarter of 2002. Natural gas production
increased to 572 mmcf/day from 566 mmcf/day in the first quarter of 2002.
UPDATED 2002 PRODUCTION FORECAST
Husky has updated its production forecast for 2002. Husky anticipates
that 2002 production will average between 295 and 315 mboe/day. Production of
light and medium crude oil and NGL is anticipated to average between 125 and
135 mbbls/day. Lloydminster heavy crude oil production is estimated to
average between 77 and 80 mbbls/day. Natural gas production is estimated to
average between 570 and 600 mmcf/day.
<<
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Industry Conditions
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
Benchmark Prices (averages) 2002 2001 2002 2001
-------------------------------------------------------------------------
West Texas Intermediate ("WTI")
(U.S. $/bbl) $ 26.25 $ 27.96 $ 23.95 $ 28.34
NYMEX natural gas
(U.S. $/mmbtu) $ 3.37 $ 4.78 $ 2.88 $ 6.03
AECO natural gas ($/GJ) $ 4.19 $ 6.85 $ 3.68 $ 8.59
WTI/Lloyd Blend differential
(U.S. $/bbl) $ 6.04 $ 11.63 $ 5.88 $ 12.27
U.S./Canadian dollar exchange
rate (U.S. $) $ 0.643 $ 0.649 $ 0.635 $ 0.652
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
The price for West Texas Intermediate ("WTI") fluctuated during the
second quarter of 2002 between U.S. $23.48/bbl and U.S. $29.38/bbl averaging
U.S. $26.25/bbl over the quarter for near-month delivery. WTI spot prices
averaged almost U.S. $2.00/bbl lower in June than in May, however spot prices
were rising at the end of June and averaged approximately U.S. $1.00/bbl
higher in the first week of July than the June average.
The NYMEX near-month price for natural gas rose during the second quarter
of 2002 reaching a high of U.S. $3.86/mmbtu on May 14, 2002 and then
fluctuated downward during the remainder of the quarter closing the quarter at
U.S. $3.25/mmbtu. The market for natural gas has been volatile as natural gas
in storage has remained at higher than usual levels.
The Company's management believes that commodity prices are likely to
remain volatile and uncertain.
Results of Operations
UPSTREAM
Revenues and Production
Husky's net revenues from upstream operations (after royalties and
hedging) increased $57 million (10 percent) to $635 million in the second
quarter of 2002 from $578 million in the second quarter of 2001. Total net
revenues from upstream operations decreased $103 million (eight percent) in
the first six months of 2002 to $1,146 million from $1,249 million in the
first six months of 2001.
<<
-------------------------------------------------------------------------
Upstream Earnings Summary (1)
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Gross revenues $ 750 $ 715 $ 1,336 $ 1,570
Royalties 115 137 190 321
-----------------------------------------
Net revenues 635 578 1,146 1,249
Costs and expenses 171 155 323 284
-----------------------------------------
EBITDA 464 423 823 965
Depletion, depreciation and
amortization ("DD&A") 202 176 402 350
-----------------------------------------
Operating profit ("EBIT") $ 262 $ 247 $ 421 $ 615
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2001 amounts as restated. Refer to note 3 to the consolidated
financial statements.
-------------------------------------------------------------------------
Net Revenue Variance Analysis (1)
-------------------------------------------------------------------------
Light/medium Lloydminster
crude oil & heavy Natural
NGL crude oil gas Other Total
-------------------------------------------------------------------------
Three months ended
June 30, 2001 $ 234 $ 79 $ 261 $ 4 $ 578
Price changes 38 80 (137) 2 (17)
Volume changes 21 24 2 - 47
Royalties (2) (8) 35 - 25
Processing - - - 2 2
---------------------------------------------------
Three months ended
June 30, 2002 $ 291 $ 175 $ 161 $ 8 $ 635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended
June 30, 2001 $ 475 $ 141 $ 619 $ 14 $1,249
Price changes 10 128 (440) 2 (300)
Volume changes 27 49 (12) - 64
Royalties 16 (12) 128 - 132
Processing - - - 1 1
---------------------------------------------------
Six months ended
June 30, 2002 $ 528 $ 306 $ 295 $ 17 $1,146
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2001 amounts as restated. Refer to note 3 to the consolidated
financial statements.
-------------------------------------------------------------------------
Average Realized Prices
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Light/medium crude oil
& NGL ($/bbl) $ 32.42 $ 28.86 $ 29.30 $ 28.79
Lloydminster heavy crude
oil ($/bbl) $ 27.02 $ 15.52 $ 23.87 $ 14.69
Natural gas ($/mcf) $ 3.98 $ 6.57 $ 3.54 $ 7.82
-------------------------------------------------------------------------
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Royalty Rates
-------------------------------------------------------------------------
Three months Six months
Percentage of upstream sales ended June 30 ended June 30
revenues, net of royalties 2002 2001 2002 2001
-------------------------------------------------------------------------
Light/medium crude oil & NGL 16% 18% 15% 19%
Lloydminster heavy crude oil 8% 8% 8% 9%
Natural gas 21% 24% 19% 24%
Total 15% 20% 14% 21%
-------------------------------------------------------------------------
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Daily Production, Before Royalties
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Light/medium crude oil & NGL
(mbbls/day) 116.6 108.6 117.1 112.0
Lloydminster heavy crude oil
(mbbls/day) 76.9 60.3 76.9 58.6
Natural gas (mmcf/day) 571.8 570.8 569.0 577.4
Barrels of oil equivalent (6:1)
(mboe/day) 288.9 264.0 288.8 266.8
-------------------------------------------------------------------------
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Product Mix
-------------------------------------------------------------------------
Three months Six months
Percentage of upstream sales ended June 30 ended June 30
revenues, net of royalties 2002 2001 2002 2001
-------------------------------------------------------------------------
Light/medium crude oil & NGL 46% 40% 46% 38%
Lloydminster heavy crude oil 27% 15% 27% 12%
Natural gas 27% 45% 27% 50%
--------------------------------------
100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
The increase in upstream revenues for the second quarter of 2002 compared
with the second quarter of 2001 was primarily due to higher production of
crude oil and natural gas, higher prices for crude oil and lower natural gas
royalties. This positive effect was partially offset by lower prices for
natural gas and NGL. During the second quarter of 2002, lower production of
light/medium crude oil from properties in Western Canada was more than offset
by production from Terra Nova. Production from the Terra Nova oil field,
offshore the east coast of Canada, commenced in January, 2002 and averaged
over 15 mbbls/day during the second quarter of 2002 (net to Husky). The
decrease in the light/medium crude oil & NGL royalty rate in 2002 was mainly
due to Terra Nova royalties, which are currently low until recovery of capital
expenditures. An eight percent decline in light and medium crude oil
production in Western Canada in the second quarter of 2002 compared with the
same period in 2001 was mainly due to higher natural declines, capital program
delays, an extended spring break-up, delayed tie-ins and higher turnaround and
maintenance activity. Lloydminster heavy crude oil production was 28 percent
higher in the second quarter of 2002 compared with the same quarter in 2001.
The higher Lloydminster production resulted primarily from the 2001/2002
drilling program, an active well optimization/workover program, increased
production from cold production wells and the addition of the Bolney/Celtic
properties during the third quarter of 2001. Natural gas production in the
second quarter of 2002 was the same as in the second quarter of 2001. Realized
heavy crude oil prices averaged 74 percent higher during the second quarter of
2002 compared to the same period in 2001. Husky's average realized price for
light and medium crude oil and NGL in the second quarter of 2002 was
$32.42/bbl, 12 percent higher than that for the same period in 2001. Realized
natural gas prices averaged 39 percent lower during the second quarter of 2002
compared with that for the second quarter in 2001.
The decrease in upstream net revenues for the first six months of 2002
compared with the first six months of 2001 was due to lower natural gas and
NGL prices and lower natural gas production, the effects of which were
partially offset by lower natural gas royalties. Natural gas production was
approximately one percent lower during the first half of 2002 as completion
and tie-in of wells from the winter drilling program were delayed.
<<
Netbacks and Operating Costs (1)
-------------------------------------------------------------------------
Light/Medium Crude Oil Netbacks (2)
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
Per boe 2002 2001 2002 2001
-------------------------------------------------------------------------
Sales revenues $ 32.33 $ 29.51 $ 29.22 $ 29.57
Royalties 4.63 5.00 3.96 5.16
Operating costs 7.30 7.50 7.46 6.92
-----------------------------------------
Netback $ 20.40 $ 17.01 $ 17.80 $ 17.49
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) 2001 amounts as restated. Refer to note 3 to the consolidated
financial statements.
(2) Includes associated co-products converted to boe.
-------------------------------------------------------------------------
Lloydminster Heavy Crude Oil Netbacks (1)
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
Per boe 2002 2001 2002 2001
-------------------------------------------------------------------------
Sales revenues $ 27.00 $ 15.73 $ 23.76 $ 15.02
Royalties 2.25 1.54 1.92 1.41
Operating costs 6.94 8.11 6.68 8.13
-----------------------------------------
Netback $ 17.81 $ 6.08 $ 15.16 $ 5.48
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Natural Gas Netbacks (2)
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
Per mcfe 2002 2001 2002 2001
-------------------------------------------------------------------------
Sales revenues $ 4.05 $ 6.42 $ 3.62 $ 7.61
Royalties 0.95 1.57 0.77 1.92
Operating costs 0.71 0.57 0.64 0.50
-----------------------------------------
Netback $ 2.39 $ 4.28 $ 2.21 $ 5.19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Upstream Netbacks (1)
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
Per boe 2002 2001 2002 2001
-------------------------------------------------------------------------
Sales revenues $ 28.21 $ 29.59 $ 25.25 $ 32.21
Royalties 4.35 5.78 3.63 6.66
Operating costs 6.19 6.19 6.03 5.75
-----------------------------------------
Netback $ 17.67 $ 17.62 $ 15.59 $ 19.80
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Includes associated co-products converted to mcfe.
>>
Higher average unit operating cost in the first half of 2002 compared
with the same period in 2001 was primarily attributable to production declines
in shallow natural gas and mature waterflood properties.
Depletion, Depreciation and Amortization ("DD&A")
Total upstream DD&A per boe was $7.69 during the second quarter of 2002
compared with $7.32 during the same period in 2001. The higher DD&A per boe
in the second quarter reflected the proportionately higher capital
requirements associated with shallow natural gas, mature waterflood oil
properties and the Terra Nova oil field development.
The same factors were responsible for the higher DD&A per boe in the
first six months of 2002 compared with the same period in 2001.
MIDSTREAM
EBITDA from midstream operations in the second quarter of 2002 decreased
60 percent to $55 million from $137 million in the second quarter of 2001. The
decrease in midstream EBITDA was due to a lower upgrading differential and
lower throughput. Production of synthetic crude oil at the upgrader was
significantly reduced during the quarter as a result of a scheduled full plant
turnaround which lasted 16 days in June. Lower earnings from infrastructure
and marketing operations were primarily due to lower pipeline throughput.
The same factors affected midstream EBITDA in the first six months of
2002 compared with the same period of 2001 except that higher income from
marketing operations partially offset the lower income from pipeline
operations.
<<
Upgrading Operations
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Gross margin $ 49 $ 142 $ 124 $ 275
Operating costs 38 53 74 122
Other expenses (recoveries) (2) 6 (3) 11
-----------------------------------------
EBITDA 13 83 53 142
DD&A 4 5 9 8
-----------------------------------------
Operating profit ("EBIT") $ 9 $ 78 $ 44 $ 134
-----------------------------------------
-----------------------------------------
Selected operating data:
Upgrader throughput (1)
(mbbls/day) 58.9 75.5 67.7 74.7
Synthetic crude oil sales
(mbbls/day) 51.3 65.6 61.2 61.0
Upgrading differential ($/bbl) 10.43 19.56 9.94 20.55
Unit margin ($/bbl) 10.55 23.84 11.20 24.95
Unit operating cost (2) ($/bbl) 7.13 7.83 6.01 9.03
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.
-------------------------------------------------------------------------
Upgrading EBITDA Variance Analysis
-------------------------------------------------------------------------
Three months ended June 30, 2001 $ 83
Volume (34)
Differential (59)
Operating costs - energy 9
Operating costs - non-energy 6
Other 8
----------
Three months ended June 30, 2002 $ 13
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Six months ended June 30, 2001 $ 142
Volume 1
Differential (152)
Operating costs - energy 42
Operating costs - non-energy 6
Other 14
----------
Six months ended June 30, 2002 $ 53
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EBITDA from upgrading operations in the second quarter of 2002 was $13
million ($53 million first six months of 2002) compared with $83 million in
the second quarter of 2001 ($142 million first six months of 2001). The lower
upgrading EBITDA in the second quarter and first six months of 2002 compared
with the same periods in 2001 was due to a narrower upgrading differential
between the price of synthetic crude oil and the cost of blended heavy crude
oil feedstock and lower throughput as a result of a full plant turnaround in
June, partially offset by lower energy related operating costs.
-------------------------------------------------------------------------
Infrastructure and Marketing
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Gross margin
- pipeline $ 14 $ 27 $ 30 $ 50
- other infrastructure
and marketing 30 30 72 62
-----------------------------------------
44 57 102 112
Other expenses 2 3 4 4
-----------------------------------------
EBITDA 42 54 98 108
DD&A 5 4 9 8
-----------------------------------------
Operating profit ("EBIT") $ 37 $ 50 $ 89 $ 100
-----------------------------------------
-----------------------------------------
Selected operating data:
Aggregate pipeline throughput
(mbbls/day) 448 583 458 567
-------------------------------------------------------------------------
>>
The lower EBITDA from infrastructure and marketing operations during the
second quarter of 2002 compared with the same period in 2001 resulted
primarily from lower pipeline throughput and margins due to increased
competition for volumes.
During the first six months of 2002, infrastructure and marketing EBITDA
was $98 million compared with $108 million in the same period in 2001. The
decrease in EBITDA in the first half of 2002 was due to substantially the same
factors as those affecting the second quarter of 2002 except that higher
income from marketing operations partially offset the lower pipeline income.
REFINED PRODUCTS
Husky's total refined products EBITDA was $30 million for the second
quarter of 2002 compared with $51 million for the second quarter of 2001.
Lower margins for asphalt products and motor fuels were partially offset by
higher sales volume of gasoline products.
The same factors affected refined products EBITDA in the first six months
of 2002 except that higher sales volume of gasoline was offset by lower sales
volume of diesel fuels.
<<
-------------------------------------------------------------------------
Light Oil Products
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Gross margin
- fuel sales $ 24 $ 25 $ 36 $ 38
- ancillary sales 6 6 12 13
-----------------------------------------
30 31 48 51
Operating expenses 7 6 14 13
Other expenses 6 4 5 7
-----------------------------------------
EBITDA 17 21 29 31
DD&A 7 6 13 12
-----------------------------------------
Operating profit ("EBIT") $ 10 $ 15 $ 16 $ 19
-----------------------------------------
-----------------------------------------
Selected operating data:
Number of fuel outlets 575 584
Fuel sales volume
(million litres/day) 7.4 7.3 7.3 7.4
Refinery throughput (mbbls/day) 7.7 10.7 9.3 10.8
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asphalt Products
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Gross margin $ 13 $ 30 $ 20 $ 39
Other expenses - - 1 1
-------------------------------------
EBITDA 13 30 19 38
DD&A 1 1 3 3
Operating profit ("EBIT") $ 12 $ 29 $ 16 $ 35
-------------------------------------
-------------------------------------
Selected operating data:
Sales volume (mbbls/day) 20.5 20.6 19.1 17.8
Refinery throughput (mbbls/day) 19.9 20.5 22.5 21.3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
CORPORATE
Interest Expense
Net interest expense was $3 million lower in the first six months of 2002
compared with the same period in 2001. During the first six months of 2002,
capitalized interest was $14 million lower than the same period in 2001 as
interest ceased to be capitalized on the Terra Nova project following
commencement of production in January 2002.
The Company's average interest rate, including interest rate swaps,
during the first six months of 2002 was 5.37 percent compared with 7.11
percent for the same period in 2001.
Foreign Exchange
The Company recorded foreign exchange gains of $57 million in the first
six months of 2002 compared with $23 million of losses during the same period
of 2001, primarily due to a strengthening of the Canadian dollar in 2002.
Effective January 1, 2002, due to a change in Canadian generally accepted
accounting principles, foreign exchange gains and losses on long-term monetary
items are no longer deferred and amortized but are now reflected in the
Statement of Earnings in the period they are determined. Foreign exchange for
the comparative prior periods presented have been adjusted to reflect this
change. The U.S./Canadian exchange rates at June 30, 2002 and December 31,
2001 expressed in Canadian dollars were $1.5187 and $1.5926, respectively and
at June 30, 2001 and December 31, 2000 were $1.5177 and $1.5002, respectively.
Income Taxes
Income tax expense was $146 million during the first six months of 2002
compared with $296 million during the same period in 2001. Lower income tax
expense in the first six months of 2002 was primarily due to lower pre-tax
earnings and to the recognition of a non-recurring adjustment to future income
taxes of $44 million resulting from reductions to the British Columbia and
Alberta corporate income tax rates, a reduction in the federal corporate
income tax rate for non-resource income and the recognition of additional tax
deductions relating to foreign exchange losses of prior years. The same period
in 2001 included a non-recurring adjustment to future income taxes of
$42 million resulting from a reduction to the Alberta corporate income tax
rate.
Sensitivity Analysis
The following table shows the annual effect on net earnings and cash flow
of changes in certain key variables. The analysis is based on business
conditions and production volumes during the second quarter of 2002. Each
separate item in the sensitivity analysis assumes the others are held
constant. While these sensitivities are applicable for the period and
magnitude of changes on which they are based, they may not be applicable in
other periods, under other economic circumstances or greater magnitudes of
change.
<<
-------------------------------------------------------------------------
Sensitivity Analysis
-------------------------------------------------------------------------
Effect on Effect on
Item Increase Pre-tax Cash Flow Net Earnings
-------------------------------------------------------------------------
($millions) ($/share)(5) ($millions) ($/share)(5)
WTI benchmark U.S. $1.00 94 0.22 59 0.14
crude oil /bbl
price
NYMEX U.S. $0.20 39 0.09 23 0.05
benchmark /mmbtu
natural gas
price (1)
Light/heavy Cdn. $1.00 (31) (0.07) (19) (0.04)
crude oil /bbl
differential(2)
Light oil Cdn. $0.005 14 0.03 8 0.02
margins /litre
Asphalt Cdn. $1.00 8 0.02 5 0.01
margins /bbl
Exchange rate U.S. $0.01 (42) (0.10) (26) (0.06)
(U.S. $ per
Cdn.$)(3)
Interest 1% (13) (0.03) (8) (0.02)
rate(4)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(1) Includes decrease in earnings related to natural gas consumption.
(2) Includes impact of upstream and upgrading operations only.
(3) Assumes no foreign exchange gain or loss. A new accounting standard
eliminates the deferral of foreign exchange gains and losses on
long-term monetary items. The impact of the Canadian dollar
strengthening by U.S. $0.01 would be an increase of $18 million in
net earnings based on June 30, 2002 U.S. $ denominated debt levels.
(4) Interest rate sensitivity based on annual weighted obligations.
(5) Based on June 30, 2002 common shares outstanding of 417.5 million.
>>
Liquidity and Capital Resources
SUMMARY
During the first six months of 2002, cash available from operating
activities amounted to $855 million, a decrease of $248 million (22 percent)
compared with the same period in 2001. Cash used for investing activities
during the first six months of 2002 amounted to $807 million, an increase of
$120 million compared with the same period in 2001. During the first six
months of 2002, cash used for investing activities were comprised of capital
expenditures of $787 million, investment in other assets of $7 million,
corporate acquisitions of $3 million and a change in non-cash working capital
of $27 million partially offset by sales of assets of $17 million.
INVESTING ACTIVITIES
Net capital investments during the first six months of 2002 were financed
primarily by cash flow from operating activities and through the utilization
of existing credit facilities.
<<
-------------------------------------------------------------------------
Capital Expenditures
-------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
-------------------------------------------------------------------------
Upstream
Exploration
Western Canada $ 37 $ 57 $ 159 $ 135
East Coast Canada - 26 15 39
International - 1 1 1
--------------------------------------
37 84 175 175
--------------------------------------
Development
Western Canada 119 129 342 300
East Coast Canada 154 28 177 55
International 22 17 41 47
--------------------------------------
295 174 560 402
--------------------------------------
332 258 735 577
--------------------------------------
Midstream
Upgrader 12 3 21 5
Infrastructure and marketing 3 5 10 30
--------------------------------------
15 8 31 35
--------------------------------------
Refined Products 9 5 13 10
Corporate 5 2 8 2
--------------------------------------
$ 361 $ 273 $ 787 $ 624
-------------------------------------------------------------------------
-------------------------------------------------------------------------
>>
Upstream
During the first half of 2002 upstream capital expenditures in Western
Canada were $501 million (second quarter of 2002 - $156 million). Exploration
and development expenditures in the Lloydminster heavy oil area amounted to
$85 million. During the first half of 2002, 126 wells were drilled in the
Lloydminster area, of which 122 were completed and equipped. In Western Canada
conventional areas 440 wells were drilled, of which 409 were completed and
equipped. Exploration spending in Western Canada during the first half of 2002
was $159 million, or 32 percent of total Western Canada upstream capital
expenditures. Exploration focus remained on plays extending from the Alberta
foothills and Deep Basin through to northeast British Columbia and northwest
Alberta.
During the first half of 2002, $192 million was spent on offshore East
Coast of Canada exploration and development projects, which include White Rose
($180 million), Terra Nova ($10 million) and other exploration ($2 million).
The Terra Nova oil field commenced production in January 2002.
During the first half of 2002, $41 million was spent on the Wenchang oil
field development project offshore southern China. This project achieved first
oil on July 7, 2002.
<<
------------------------------------------------------------------------
Wells Drilled(1)
------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
Gross Net Gross Net Gross Net Gross Net
------------------------------------------------------------------------
Western Canada
Exploration Oil 6 6 15 15 12 11 62 60
Gas 19 18 6 5 107 101 78 73
Dry 1 1 3 3 10 10 29 28
-----------------------------------------------
26 25 24 23 129 122 169 161
-----------------------------------------------
Development Oil 120 112 132 129 172 156 242 231
Gas 14 10 19 17 240 226 133 111
Dry 6 6 8 7 25 24 31 29
-----------------------------------------------
140 128 159 153 437 406 406 371
-----------------------------------------------
166 153 183 176 566 528 575 532
-----------------------------------------------
-----------------------------------------------
(1) Excludes stratigraphic test wells.
>>
Midstream
Midstream capital expenditures for property, plant and equipment during
the first half of 2002 were $31 million including $21 million for the Husky
Lloydminster Upgrader (2001 - $5 million) and $10 million for pipeline and
cogeneration projects (2001 - $30 million).
Refined Products
Refined products capital expenditures amounted to $13 million during the
first half of 2002, including $6 million for marketing outlet improvements,
$1 million on asphalt distribution systems, $5 million for various
improvements at the Lloydminster asphalt refinery and $1 million at the Prince
George refinery compared with total refined product capital expenditures of
$10 million in the first half of 2001.
FINANCING ACTIVITIES
Total debt, net of cash and cash equivalents of $172 million, was
$2,176 million at June 30, 2002 compared with $2,192 million at December 31,
2001.
Effective June 14, 2002, the Company issued U.S. $400 million of 6.25
percent notes under a U.S. $1 billion base shelf prospectus dated June 6,
2002. See note 6 to the consolidated financial statements.
The Company believes its internally generated liquidity, together with
access to external credit resources, will be sufficient to satisfy existing
commitments and plans, and also to provide adequate flexibility to take
advantage of potential business opportunities.
<<
Common Share Information
Six months Year ended
ended June 30 December 31
(thousands of shares, except per share amounts) 2002 2001
------------------------------------------------------------------------
Share price(1) High $ 17.98 $ 20.95
Low $ 14.20 $ 13.10
Close at end of period $ 16.66 $ 16.47
Average daily trading volume 520 625
Weighted average number of common shares outstanding
Basic 417,225 416,100
Diluted 419,313 418,640
Number of common shares
outstanding at end of period 417,472 416,878
------------------------------------------------------------------------
------------------------------------------------------------------------
(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.
>>
Certain statements contained in this release, including statements which
may contain words such as "could", "expect", "believe", "will" and similar
expressions and statements relating to matters that are not historical facts
are forward-looking statements. Actual future results may differ materially.
Husky's annual report to shareholders and other documents filed with
securities regulatory authorities describe the risks, uncertainties and other
factors, such as changes in business plans and estimated amounts and timing of
capital expenditures and changes in estimates of future production, that could
influence actual results.
<<
CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------
June 30 December 31
(millions of dollars) 2002 2001
------------------------------------------------------------------------
(unaudited) (audited)
Assets
Current assets
Cash and cash equivalents $ 172 $ -
Accounts receivable 418 376
Inventories 244 226
Prepaid expenses 22 24
----------------------
856 626
----------------------
Property, plant and equipment -
(full cost accounting) 13,836 13,078
Less accumulated depletion,
depreciation and amortization 4,771 4,363
----------------------
9,065 8,715
----------------------
Other assets (note 3) 44 29
----------------------
$ 9,965 $ 9,370
----------------------
----------------------
Liabilities and Shareholders' Equity
Current liabilities
Bank operating loans (note 5) $ - $ 100
Accounts payable and accrued liabilities 821 821
Long-term debt due within one year (note 6) 172 144
----------------------
993 1,065
----------------------
Long-term debt (note 6) 2,176 1,948
Site restoration provision 237 212
Future income taxes (note 8) 1,772 1,659
Shareholders' equity
Capital securities and accrued return 349 367
Common shares (note 7) 3,401 3,397
Retained earnings 1,037 722
----------------------
4,787 4,486
----------------------
$ 9,965 $ 9,370
----------------------
----------------------
Commitments (note 9)
Common shares outstanding (millions) (note 7) 417.5 416.9
------------------------------------------------------------------------
------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2001 amounts as restated.
CONSOLIDATED STATEMENTS OF EARNINGS
(unaudited)
------------------------------------------------------------------------
Three months Six months
(millions of dollars, ended June 30 ended June 30
except per share amounts) 2002 2001 2002 2001
------------------------------------------------------------------------
Sales and operating revenues,
net of royalties (note 3) $1,659 $1,731 $3,018 $3,511
Costs and expenses
Cost of sales and operating
expenses (note 3) 1,105 1,110 2,008 2,215
Selling and administration expenses 18 23 38 40
Depletion, depreciation
and amortization 223 196 444 388
Interest - net (note 6) 24 26 51 54
Foreign exchange (note 3) (65) (50) (57) 23
Other - net 2 1 (1) 4
-----------------------------------
1,307 1,306 2,483 2,724
-----------------------------------
Earnings before income taxes 352 425 535 787
-----------------------------------
Income taxes (note 8)
Current 6 5 34 10
Future 83 121 112 286
-----------------------------------
89 126 146 296
-----------------------------------
Net earnings $ 263 $ 299 $ 389 $ 491
-----------------------------------
-----------------------------------
Earnings per share (note 11)
Basic $ 0.64 $ 0.74 $ 0.93 $ 1.15
Diluted $ 0.64 $ 0.73 $ 0.93 $ 1.15
Weighted average number of common
shares outstanding (millions) (note 11)
Basic 417.4 415.9 417.2 415.8
Diluted 419.6 418.3 419.3 417.9
------------------------------------------------------------------------
------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(unaudited)
------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
(millions of dollars) 2002 2001 2002 2001
------------------------------------------------------------------------
Beginning of period $ 805 $ 391 $ 722 $ 304
Net earnings 263 299 389 491
Dividends on common shares (37) (38) (75) (75)
Return on capital securities (net of
related taxes and foreign exchange) 6 5 1 (12)
Foreign exchange (retroactive adjustment) - - - (51)
-----------------------------------
End of period $1,037 $ 657 $1,037 $ 657
------------------------------------------------------------------------
------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2001 amounts as restated.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
------------------------------------------------------------------------
Three months Six months
(millions of dollars, ended June 30 ended June 30
except per share amounts) 2002 2001 2002 2001
------------------------------------------------------------------------
Operating activities
Net earnings $ 263 $ 299 $ 389 $ 491
Items not affecting cash
Depletion, depreciation
and amortization 223 196 444 388
Future income taxes 83 121 112 286
Foreign exchange - non cash (note 3) (71) (54) (70) 15
Other - (1) (4) 1
-----------------------------------
Cash flow from operations 498 561 871 1,181
Change in non-cash working
capital (note 10) (2) (113) (16) (78)
-----------------------------------
496 448 855 1,103
-----------------------------------
Financing activities
Bank operating loans financing - net (120) (53) (100) (27)
Long-term debt issue 772 - 972 -
Long-term debt repayment (535) (1) (646) (303)
Return on capital securities payment - - (16) (15)
Debt issue costs (7) - (7) -
Deferred credits - 3 - -
Proceeds from exercise of stock options 1 2 4 2
Dividends on common shares (37) (38) (75) (75)
Change in non-cash working
capital (note 10) (5) 71 (8) 2
-----------------------------------
69 (16) 124 (416)
-----------------------------------
Available for investing 565 432 979 687
-----------------------------------
Investing activities
Capital expenditures (361) (273) (787) (624)
Corporate acquisitions (1) (29) (3) (34)
Asset sales 5 9 17 36
Other assets (9) 2 (7) 3
Change in non-cash working
capital (note 10) (27) (141) (27) (68)
-----------------------------------
(393) (432) (807) (687)
-----------------------------------
Increase in cash and cash equivalents 172 - 172 -
Cash and cash equivalents
at beginning of period - - - -
-----------------------------------
Cash and cash equivalents
at end of period $ 172 $ - $ 172 $ -
-----------------------------------
-----------------------------------
Cash flow from operations per
share (note 11)
Basic $ 1.18 $ 1.33 $ 2.05 $ 2.80
Diluted $ 1.17 $ 1.32 $ 2.04 $ 2.79
------------------------------------------------------------------------
------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements. 2001 amounts as restated.
Notes to the Consolidated Financial Statements
Six months ended June 30, 2002 (unaudited)
Except where indicated and per share amounts, all dollar amounts
are in millions of Canadian dollars.
Note 1 Segmented Financial Information
------------------------------------------------------------------------
Midstream
---------------------------------
Infrastructure
Upstream Upgrading and Marketing
---------------------------------------------------
2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Three months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 635 $ 578 $ 195 $ 259 $ 958 $ 839
Costs and expenses(2) 171 155 182 176 916 785
------------------------------------------------------
EBITDA 464 423 13 83 42 54
Depletion, depreciation
and amortization 202 176 4 5 5 4
------------------------------------------------------
Operating profit
("EBIT") $ 262 $ 247 $ 9 $ 78 $ 37 $ 50
------------------------------------------------------
------------------------------------------------------
Interest - net
Earnings (loss) before
income taxes
Current income taxes
Future income taxes
Net earnings (loss)
------------------------------------------------------
------------------------------------------------------
Capital expenditures -
Three months ended
June 30 $ 332 $ 258 $ 12 $ 3 $ 3 $ 5
------------------------------------------------------
------------------------------------------------------
Six months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 1,146 $ 1,249 $ 416 $ 484 $ 1,910 $ 2,431
Costs and expenses(2) 323 284 363 342 1,812 2,323
------------------------------------------------------
EBITDA 823 965 53 142 98 108
Depletion, depreciation
and amortization 402 350 9 8 9 8
------------------------------------------------------
Operating profit
("EBIT") $ 421 $ 615 $ 44 $ 134 $ 89 $ 100
------------------------------------------------------
------------------------------------------------------
Interest - net
Earnings (loss)
before income taxes
Current income taxes
Future income taxes
Net earnings (loss)
------------------------------------------------------
------------------------------------------------------
Capital expenditures
- Six months ended
June 30 $ 735 $ 577 $ 21 $ 5 $ 10 $ 30
------------------------------------------------------
------------------------------------------------------
Identifiable assets -
As at June 30(3) $ 7,668 $ 6,799 $ 617 $ 572 $ 411 $ 390
------------------------------------------------------------------------
------------------------------------------------------------------------
Corporate and
Refined Products Eliminations(4) Total
---------------------------------------------------
2002 2001 2002 2001 2002 2001
------------------------------------------------------------------------
Three months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 322 $ 345 $ (451) $ (290) $ 1,659 $ 1,731
Costs and expenses(2) 292 294 (501) (326) 1,060 1,084
------------------------------------------------------
EBITDA 30 51 50 36 599 647
Depletion, depreciation
and amortization 8 7 4 4 223 196
------------------------------------------------------
Operating profit
("EBIT") $ 22 $ 44 46 32 376 451
------------------
------------------
Interest - net 24 26 24 26
------------------------------------
Earnings (loss) before
income taxes 22 6 352 425
Current income taxes 6 5 6 5
Future income taxes 83 121 83 121
------------------------------------
Net earnings (loss) $ (67) $ (120) $ 263 $ 299
------------------------------------------------------
------------------------------------------------------
Capital expenditures -
Three months ended
June 30 $ 9 $ 5 $ 5 $ 2 $ 361 $ 273
------------------------------------------------------
------------------------------------------------------
Six months ended
June 30(1)
Sales and operating
revenues, net of
royalties $ 553 $ 646 $(1,007) $(1,299) $ 3,018 $ 3,511
Costs and expenses(2) 505 577 (1,015) (1,244) 1,988 2,282
------------------------------------------------------
EBITDA 48 69 8 (55) 1,030 1,229
Depletion, depreciation
and amortization 16 15 8 7 444 388
------------------------------------------------------
Operating profit
("EBIT") $ 32 $ 54 - (62) 586 841
------------------
------------------
Interest - net 51 54 51 54
------------------------------------
Earnings (loss)
before income taxes (51) (116) 535 787
Current income taxes 34 10 34 10
Future income taxes 112 286 112 286
------------------------------------
Net earnings (loss) $ (197) $ (412) $ 389 $ 491
------------------------------------------------------
------------------------------------------------------
Capital expenditures
- Six months ended
June 30 $ 13 $ 10 $ 8 $ 2 $ 787 $ 624
------------------------------------------------------
------------------------------------------------------
Identifiable assets -
As at June 30(3) $ 321 $ 320 $ 948 $ 963 $ 9,965 $ 9,044
------------------------------------------------------
------------------------------------------------------
(1) 2001 amounts as restated.
(2) Costs and expenses include cost of sales and operating expenses,
selling and administration expenses, foreign exchange and other -
net.
(3) Identifiable assets by segment are the total assets specifically
attributable to those operations at June 30. Corporate accounts
include accounts receivable, inventories, prepaid expenses, other
assets and corporate assets.
(4) 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, 2001, 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, 2001. Certain information provided for prior periods
has been reclassified to conform with current presentation.
Cash and Cash Equivalents
Cash and cash equivalents consists of cash on hand and deposits
with a maturity of less than three months.
Note 3 Accounting Changes
Effective January 1, 2002, the Company retroactively adopted the
revised recommendations of the Canadian Institute of Chartered
Accountants on Foreign Currency Translation. The new
recommendations eliminated the deferral and amortization of
foreign exchange gains and losses on long-term monetary items.
This change resulted in a reduction of retained earnings at
January 1, 2001 of $51 million. This change also resulted in a
reduction to other assets of $133 million, a reduction to the
future income tax liability of $36 million and an increase to
capital securities of $17 million as at December 31, 2001. Net
earnings for the six months ended June 30, 2001 were reduced by
$5 million and retained earnings were reduced by $8 million,
which included an adjustment to the accrued return on the capital
securities.
In 2001 and previously, the Company presented certain crown
charges as a component of operating expenses. These charges have
been reclassified as royalties for 2002 and for all comparative
periods presented in these financial statements. There is no
impact on the earnings or cash flow of the Company as a result of
this change.
Note 4 Financial Instruments and Risk Management
Interest Rate Risk
The Company has entered into interest rate swap arrangements
whereby the fixed interest rate coupon on certain debt was
swapped to floating rates with the following terms:
<<
Amount
Debt (millions) Swap Maturity Swap Rate (%)
-------------------------------------------------------------------------
6.875% notes U.S. $ 35 November 15, 2003 U.S. LIBOR - 13 bps
6.95% medium-term
notes $200 July 14, 2009 CDOR + 175 bps
7.125% notes U.S. $150 November 15, 2006 U.S. LIBOR + 235 bps
7.55% debentures U.S. $200 November 15, 2011 U.S. LIBOR + 194 bps
6.25% senior notes U.S. $150 June 15, 2012 U.S. LIBOR + 88 bps
-------------------------------------------------------------------------
>>
During the first six months of 2002, the Company recognized a
gain of $12 million from interest rate management activities
(2001 - nil).
Sale of Accounts Receivable
The Company has an agreement to sell trade receivables of up to
$220 million on a continual basis. The agreement calls for
purchase discounts, based on Canadian commercial paper rates, to
be paid on an ongoing basis. The average effective rate during
the first six months of 2002 was 2.60 percent (first six months
2001 - 5.67 percent). The Company has potential exposure to an
immaterial amount of credit loss under this agreement. At
June 30, 2002, $220 million of trade receivables had been sold
under the agreement.
Note 5 Bank Operating Loans
At June 30, 2002 the Company did not have any outstanding bank
operating loans compared with $100 million at December 31, 2001.
The Company has $195 million in short-term borrowing facilities
available to it. The interest rates applicable to these
facilities vary and are based on Canadian prime, Bankers'
Acceptance, money market rates or U.S. dollar equivalents.
Note 6 Long-term Debt
<<
------------------------------------------------------------------------
June 30 Dec. 31
Maturity 2002 2001
------------------------------------------------------------------------
Long-term debt
Revolving syndicated
credit facility -2001 U.S. $116 2006 $ - $ 185
6.25% notes -2002 U.S. $400 2012 607 -
6.875% notes -2002 & 2001 U.S. $150 2003 228 239
7.125% notes -2002 & 2001 U.S. $150 2006 228 239
7.55% debentures -2002 & 2001 U.S. $200 2016 304 318
8.45% senior
secured bonds -2002 U.S. $168;
2001 U.S. $173 2002-12 255 276
Private placement
notes -2002 U.S. $83;
2001 U.S. $85 2003-5 126 135
Medium-term notes 2002-9 600 700
----------------
Total long-term debt 2,348 2,092
Amount due within one year (172) (144)
----------------
$ 2,176 $ 1,948
------------------------------------------------------------------------
------------------------------------------------------------------------
>>
At June 30, 2002, the Company did not have any borrowings under
the Company's syndicated credit facility. During the second
quarter the amount of this facility was reduced from $1 billion
to $940 million. Interest rates under the facility vary based on
Canadian prime, Bankers' Acceptance, U.S. LIBOR or U.S. base
rate, depending on the borrowing option selected, credit ratings
assigned by certain rating agencies to the Company's senior
unsecured debt and whether the facility is revolving or
non-revolving.
Effective June 14, 2002 the Company issued U.S. $400 million of
6.25 percent notes due June 15, 2012. The notes were priced to
yield 6.312 percent. Net proceeds from the issue were used to
repay bank indebtedness and for general corporate purposes. The
notes are redeemable at the option of the Company at any time.
Interest is payable semi-annually. The notes were issued under a
base shelf prospectus dated June 6, 2002 filed with securities
regulatory authorities in Canada and the United States. The
prospectus permits Husky to offer for sale, from time to time, up
to U.S. $1 billion of debt securities during the 25 months from
June 6, 2002. The notes rank on equal footing with other
unsecured indebtedness of the Company.
<<
Interest - net consists of:
------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
------------------------------------------------------------------------
Long-term debt $ 29 $ 37 $ 60 $ 77
Short-term debt 1 1 2 2
---------------------------------
30 38 62 79
Amount capitalized (4) (12) (10) (24)
---------------------------------
26 26 52 55
Interest income (2) - (1) (1)
---------------------------------
$ 24 $ 26 $ 51 $ 54
------------------------------------------------------------------------
------------------------------------------------------------------------
>>
Note 7 Share Capital
The Company's authorized share capital consists of an unlimited
number of no par value common and preferred shares. Changes to
issued share capital during 2002 were as follows:
<<
------------------------------------------------------------------------
Number of
Common Shares Amount
------------------------------------------------------------------------
Balance at December 31, 2001 416,878,093 $ 3,397
Exercised for cash - options and warrants 593,465 4
------------------------------------------------------------------------
Balance at June 30, 2002 417,471,558 $ 3,401
------------------------------------------------------------------------
------------------------------------------------------------------------
>>
As the Company follows the intrinsic value method of accounting
for stock-based compensation, no compensation cost has been
recognized for its fixed stock option plan. Had compensation cost
for the Company's stock option plan been determined based on the
fair value at the grant dates for awards under the plan after
January 1, 2002, the Company's pro-forma net earnings and
earnings per share would have been the same as those reported.
The weighted average fair market value of options granted in the
first six months of 2002 was $5.99 per option. The fair value of
each option granted was estimated on the date of grant using the
Modified Black-Scholes option-pricing model with the following
assumptions:
<<
------------------------------------------------------------------------
Modified Black-Scholes Assumptions
------------------------------------------------------------------------
Risk-free interest rate 3.5%
Volatility 45%
Expected life Five years
Expected annual dividend per share $0.36
------------------------------------------------------------------------
------------------------------------------------------------------------
A summary of the status of the Company's fixed stock option plan
and changes during 2002 is presented below:
------------------------------------------------------------------------
Three months ended Six months ended
June 30, 2002 June 30, 2002
------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Shares Exercise Shares Exercise
Fixed Options (thousands) Prices (thousands) Prices
------------------------------------------------------------------------
Outstanding, beginning
of period 8,413 $13.84 8,602 $13.78
Granted 129 $16.40 329 $16.32
Exercised (80) $13.63 (243) $13.58
Forfeited (153) $14.36 (379) $14.19
---------------------------------------------
Outstanding, June 30 8,309 $13.87 8,309 $13.87
---------------------------------------------
---------------------------------------------
Options exercisable at June 30 2,742 $13.79
------------------------------------------------------------------------
------------------------------------------------------------------------
>>
At June 30, 2002, the options outstanding had exercise prices
ranging from $11.16 to $19.76 with a weighted average contractual
life of 3.2 years.
Shares potentially issuable on the settlement of the capital
securities have not been included in the determination of diluted
earnings and cash flow per share, as the Company has neither the
obligation nor intention to settle amounts due through the issue
of shares.
Note 8 Income Taxes
Income tax expense in the first six months of 2002 included a
non-recurring adjustment to future income taxes of $44 million
resulting from reductions to the British Columbia and Alberta
corporate income tax rates, a reduction in the federal corporate
income tax rate for non-resource income and the recognition of
additional tax deductions relating to foreign exchange losses of
prior years. The same period in 2001 included a non-recurring
adjustment to future income taxes of $42 million resulting from a
reduction to the Alberta corporate income tax rate.
Note 9 Commitments
The Company has awarded various contracts for the construction of
the floating production, storage and offloading vessel and
several other components of the White Rose development project
with expected completion dates in 2005.
Note 10 Cash Flows
<<
------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
------------------------------------------------------------------------
a) Changes in non-cash working
capital were as follows:
Decrease (increase) in non-cash
working capital
Accounts receivable $ 115 $ 114 $ (38) $ 106
Inventories (17) (35) (18) (48)
Prepaid expenses 4 (1) 2 (1)
Accounts payable and
accrued liabilities (136) (261) 3 (201)
----------------------------------
Change in non-cash working capital (34) (183) (51) (144)
Relating to:
Financing activities (5) 71 (8) 2
Investing activities (27) (141) (27) (68)
----------------------------------
Operating activities $ (2) $(113) $ (16) $ (78)
----------------------------------
----------------------------------
b) Other cash flow information:
Cash taxes paid $ - $ 5 $ 14 $ 13
----------------------------------
----------------------------------
Cash interest paid $ 35 $ 37 $ 70 $ 73
----------------------------------
----------------------------------
------------------------------------------------------------------------
------------------------------------------------------------------------
Note 11 Net Earnings and Cash Flow from Operations Per Common Share
------------------------------------------------------------------------
Three months Six months
ended June 30 ended June 30
2002 2001 2002 2001
------------------------------------------------------------------------
Cash flow from operations $ 498 $ 561 $ 871 $ 1,181
Return on capital securities (7) (7) (15) (16)
------------------------------------
Cash flow from operations available
to common shareholders $ 491 $ 554 $ 856 $ 1,165
------------------------------------
------------------------------------
Net earnings $ 263 $ 299 $ 389 $ 491
Return on capital securities (net of
related taxes and foreign exchange) 6 7 - (12)
------------------------------------
Net earnings available to
common shareholders $ 269 $ 306 $ 389 $ 479
------------------------------------
------------------------------------
Weighted average number of common
shares outstanding
- Basic (millions) 417.4 415.9 417.2 415.8
Effect of dilutive stock options
and warrants 2.2 2.4 2.1 2.1
------------------------------------
Weighted average number of common
shares outstanding
- Diluted (millions) 419.6 418.3 419.3 417.9
------------------------------------
------------------------------------
Cash flow from operations
Per share - Basic $ 1.18 $ 1.33 $ 2.05 $ 2.80
- Diluted $ 1.17 $ 1.32 $ 2.04 $ 2.79
Net earnings
Per share - Basic $ 0.64 $ 0.74 $ 0.93 $ 1.15
- Diluted $ 0.64 $ 0.73 $ 0.93 $ 1.15
------------------------------------------------------------------------
------------------------------------------------------------------------
>>
Terms and Abbreviations
bbls barrels
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
mcfe thousand cubic feet of gas equivalent
GJ gigajoule
mmbtu million British Thermal Units
mmlt million long tons
NGL natural gas liquids
hectare 1 hectare is equal to 2.47 acres
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
EBIT Earnings from operations before interest and
taxes (operating profit)
EBITDA Earnings from operations before interest,
income taxes and depletion, depreciation and
amortization
Equity Capital securities and accrued return, shares
and retained earnings
Free Cash Flow Cash flow from operations less capitalized
administration and capitalized interest
Total Debt Long-term debt including current portion and
short-term
Cold Production A production process that achieves high
recovery rates through the use of progressive
cavity pumps, which simultaneously produce
heavy oil and sand from unconsolidated
formations.
Natural gas converted on the basis that six mcf equals one barrel of oil.
In this report, the terms "Husky Energy Inc.","Husky" or "the Company"
mean Husky Energy Inc. and its subsidiaries and partnership interests on a
consolidated basis.
Husky Energy will host a conference call for analysts and investors on
Thursday, August 1, 2002 at 4:15 p.m. Eastern time to discuss Husky's second
quarter results. To participate, please dial 1-888-568-1774 beginning at
4:05 p.m. Eastern time. Media are invited to participate in the call on a
listen-only basis by dialing 1-888-568-1403 beginning at 4:05 p.m.
Those who are unable to listen to the call live may listen to a recording
of the call by dialing 1-800-558-5253 one hour after the completion of the
call, approximately 6:15 p.m. Eastern time, then dialing reservation number
20737262. The PostView will be available until Thursday, August 8, 2002.
SOURCE Husky Energy Inc.
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CONTACT:
Investor Relations: Richard M. Alexander,
Vice President, Investor Relations and Communications, Tel:
403-298-6952, Fax: 403-750-5010, Media Relations Donald Campbell
Manager, Corporate Communications Tel: 403-298-7088, Fax:
403-298-6515; To request a free copy of this organization's
annual report, please go to http://www.newswire.ca and click on
reports@cnw.
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