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HUSKY ENERGY INC. TSX: HSE 
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Jul 23, 2008 17:22 ET
Husky Energy Reports Second Quarter and First Six Months Results For 2008
CALGARY, ALBERTA--(Marketwire - July 23, 2008) - Husky Energy Inc. (TSX:HSE) reported net earnings of $1.36 billion or $1.61 per share (diluted) in the second quarter of 2008, an increase of 89 percent from $721 million or $0.85 per share (diluted) in the same quarter of 2007. Cash flow from operations in the second quarter of 2008 was $2.1 billion or $2.46 per share (diluted), a 66 percent increase compared with $1.3 billion or $1.48 per share (diluted) in the same quarter of 2007. Sales and operating revenues, net of royalties, were $7.20 billion in the second quarter of 2008, an increase of 128 percent compared with $3.16 billion in the same quarter of 2007.
"Husky achieved record results in the second quarter of 2008 in terms of earnings, cash flow and revenue in a strong commodity price environment," said John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "In the second quarter, our U.S. refining facilities also contributed to our strong results. In addition, excellent progress was made in the development of our major growth projects and we continued to strengthen our financial position."
In the second quarter of 2008, total production averaged 359,100 barrels of oil equivalent per day, compared with 379,100 barrels of oil equivalent per day in the second quarter of 2007, a reduction of 5 percent. Total crude oil and natural gas liquids production was 256,100 barrels per day, compared with 276,500 barrels per day in 2007. The decrease in crude oil production was mainly due to the suspension of operations at White Rose for 11 days due to severe ice pack and iceberg conditions and the advancement of a scheduled 14 day turnaround at Terra Nova. Natural gas production was 618 million cubic feet per day, compared with 616 million cubic feet per day in the same period of 2007.
For the first six months of 2008, Husky's net earnings were $2.3 billion or $2.65 per share (diluted), compared with $1.4 billion or $1.61 per share (diluted) in the first six months of 2007. Cash flow from operations was $3.6 billion or $4.28 per share (diluted) in the first six months of 2008, compared with $2.6 billion or $3.04 per share (diluted) in the same period of 2007. Sales and operating revenues, net of royalties, were $12.3 billion in the first six months of 2008, compared with $6.4 billion in the first six months of 2007.
Production for the first six months of 2008 was 354,700 barrels of oil equivalent per day, compared with 384,600 barrels of oil equivalent per day in the same period in 2007. Crude oil and natural gas liquids production was 253,900 barrels per day, compared with 279,900 barrels per day in the first six months of 2007 reflecting the advancement of scheduled turnarounds at Terra Nova and White Rose originally planned later in 2008 and the severe ice pack and iceberg conditions off the East Coast of Canada. Natural gas production was 604 million cubic feet per day, compared with 628 million cubic feet per day during the same period of 2007 as a result of a strategic decision in 2007 to reduce natural gas drilling due to weak gas prices.
Work on area infrastructure and site preparation, including roads and well pads, progressed on schedule for the Sunrise Oil Sands Project. Phase one of the Sunrise Project for 60,000 barrels per day of bitumen is expected to be operational in late 2012, subject to corporate sanction.
Planning for the development of the McMullen property located in the west central region of the Athabasca oil sands of northern Alberta progressed. Husky plans to develop production through a multi-well drilling program in 2008 using cold production technology.
The White Rose - North Amethyst satellite development off Canada's East Coast remains on schedule for a late 2009 or early 2010 start up. The West White Rose satellite development is planned for production in 2011.
Offshore China, Husky increased its holdings by signing a petroleum contract for a new exploration block, Block 63/05. Husky also completed the acquisition of 3-D seismic data on Blocks 29/26, 29/06 and 35/18 in the second quarter. The drilling rig Seadrill West Hercules is currently undergoing commissioning in South Korea. Husky plans to commence delineation drilling on the Liwan 3-1 discovery in the third quarter of 2008.
In Indonesia, Husky completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. The agreement covers the development and further exploration of the Madura Strait Production Sharing Contract ("PSC"). The Madura BD field development plan was approved and the PSC extension has been submitted to the regulatory authorities for approval.
In the downstream business, Husky completed the conceptual stage of the reconfiguration for the Lima refinery to process heavier feedstocks. With the completion of the BP/Husky joint venture, Husky is working with BP on the reconfiguration of the Toledo refinery to process bitumen feedstock.
Following the completion of the turnarounds at White Rose and Terra Nova in the first half of 2008, crude oil production is expected to increase from current levels in the second half of the year. However, the severe ice conditions which suspended production at White Rose during the first half of the year and the ramp-up of production at the Tucker Oil Sands project will impact our annual production. Production for 2008 is now expected to be five to seven percent below our guidance range.
Husky continues to strengthen its financial position and balance sheet. Total long-term debt including current portion at June 30, 2008 was $2,129 million compared with $2,814 million at December 31, 2007. Debt to capital employed improved to 14 percent at June 30, 2008 from 19 percent at December 31, 2007. Debt to cash flow from operations decreased to 0.3 times at June 30, 2008 compared with 0.5 times at December 31, 2007.
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A") JULY 23, 2008
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Table of Contents
1. Summary of Quarterly Financial 7. Risk Management
Results
2. Capability to Deliver Results 8. Critical Accounting Estimates
and the Strategic Plan
3. Key Growth Highlights 9. Changes in Accounting Policies
4. Business Environment 10. Outstanding Share Data
5. Results of Operations 11. Reader Advisories
6. Liquidity and Capital Resources 12. Forward-Looking Statements and
Information
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1. Summary of Quarterly Financial Results
The following table shows our net earnings by industry sector and includes corporate expenses and intersegment profit eliminations.
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Three months ended
June 30 March 31 Dec. 31 Sept. 30 June 30 March 31
(millions of dollars,
except per share
amounts and ratios) 2008 2008 2007 2007 2007 2007
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Sales and operating
revenues, net of
royalties $ 7,199 $ 5,086 $ 4,760 $ 4,351 $ 3,163 $ 3,244
Net earnings by sector
Upstream $ 1,239 $ 717 $ 864 $ 516 $ 636 $ 580
Midstream 153 144 218 129 77 111
Downstream 194 38 103 121 53 20
Corporate and
eliminations (223) (12) (111) 3 (45) (61)
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Net earnings $ 1,363 $ 887 $ 1,074 $ 769 $ 721 $ 650
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Per share - Basic and
diluted $ 1.61 $ 1.04 $ 1.26 $ 0.91 $ 0.85 $ 0.77
Cash flow from
operations 2,090 1,541 1,425 1,420 1,257 1,324
Per share - Basic and
diluted 2.46 1.82 1.68 1.67 1.48 1.56
Ordinary quarterly
dividend per common
share 0.40 0.33 0.33 0.25 0.25 0.25
Special dividend per
common share - - - - - 0.25
Total assets 25,296 24,391 21,697 20,718 17,969 17,781
Total long-term debt
including current
portion 2,129 3,019 2,814 2,835 1,423 1,527
Return on equity (1)
(percent) 34.9 31.2 30.2 26.6 27.1 32.1
Return on average
capital employed (1)
(percent) 30.9 26.5 25.7 22.3 23.8 27.3
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Three months ended
Dec. 31 Sept. 30
(millions of dollars, except per share amounts
and ratios) 2006 2006
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Sales and operating revenues, net of royalties $ 3,084 $ 3,436
Net earnings by sector
Upstream $ 453 $ 608
Midstream 105 87
Downstream 10 28
Corporate and eliminations (26) (41)
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Net earnings $ 542 $ 682
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Per share - Basic and diluted $ 0.64 $ 0.80
Cash flow from operations 1,207 1,224
Per share - Basic and diluted 1.42 1.44
Ordinary quarterly dividend per common share 0.25 0.25
Special dividend per common share - -
Total assets 17,933 17,324
Total long-term debt including current portion 1,611 1,722
Return on equity (1) (percent) 31.8 34.2
Return on average capital employed (1) (percent) 27.0 28.7
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(1) Calculated for the 12 months ended for the dates shown.
Analysis of Consolidated Earnings
Second Quarter
Sales and operating revenues in the second quarter of 2008 were more than double the same period in 2007 due to increased commodity prices, the addition of the Lima and Toledo refineries and the Minnedosa ethanol plant. During the second quarter of 2008, sales prices realized by Husky averaged U.S. $106/bbl (light, medium and heavy crude combined) compared with $57/bbl average for the second quarter of 2007. Realized natural gas prices averaged $9.14/mcf for the second quarter compared with $6.91/mcf during the same period in 2007. Commodity price increases in the upstream sector more than offset lower production.
Production in the second quarter averaged 359,100 boe per day compared with 379,100 boe per day in the same period in 2007. Production levels were lower in the second quarter due to the acceleration, from the third quarter, of the 2008 scheduled 14 day maintenance shut down at Terra Nova. Severe ice pack and iceberg conditions off the East Coast continued to be a factor in the second quarter, suspending production for 11 days and increasing operating costs at White Rose.
Operating revenues earned in the midstream sector increased significantly as a result of increased commodity prices. This was offset by corresponding increases in operating costs, largely made up of the cost of acquiring product for resale.
Downstream operating revenues and net earnings in 2008 include U.S. refining and marketing results from the Lima and Toledo refineries. The Lima refinery was acquired effective July 1, 2007 and 50% of the Toledo refinery was acquired on March 31, 2008 with an effective date of January 1, 2008. Earnings from Toledo during the period January 1, 2008 to March 31, 2008 have been included as an adjustment to the acquisition cost. In Canada, the addition of the Minnedosa ethanol plant contributed to increased operating revenues, operating costs and net earnings. The addition of these assets is the primary driver behind the increase in downstream revenue, operating costs and net earnings compared with the second quarter of 2007.
Six Months
Operating revenues increased 92% to $12.3 billion in the first six months of 2008 compared with the same period in 2007. Net earnings in the first six months of 2008 increased 64% to $2.3 billion compared with the same period in 2007. The primary drivers are the same as those discussed above impacting the second quarter.
Prices realized by Husky in the first half of 2008 were $93/bbl for light, medium and heavy oil combined and $55/bbl during the same period in 2007. Natural gas prices in 2008 averaged $8.11/mcf compared with $6.92/mcf during the same period in 2007.
Production during the six month period averaged 354,700 boe per day compared with 384,600 boe per day in the same period in 2007. In addition to the factors described above, production in the first quarter in Western Canada was impacted by extreme cold weather conditions, resulting in lower natural gas production and on the East Coast, the White Rose 2008 scheduled maintenance shut down was accelerated from August. The maintenance was moved forward in order to take advantage of an unplanned production shut down in the first quarter, which was due to operational issues.
Primary drivers in midstream and downstream operating revenue and net earnings for the first six months are the same as those impacting the second quarter.
2. Capability to Deliver Results and the Strategic Plan
Our current capacity to deliver results and the strategic plan are described in our annual MD&A and also in our Annual Information Form that are available from www.sedar.com and www.sec.gov.
In summary, our strategy is to continue to exploit our oil and gas asset base in Western Canada while expanding into new areas with large scale sustainable growth potential. Our plans include projects in Canada (the Alberta oil sands, the basins off the East Coast of Canada and the Central Mackenzie River Valley), Asia (the South China Sea, the Madura Strait and the East Java Sea) and offshore Greenland. In the midstream and downstream sectors we are enhancing performance and capturing new value throughout the value chain by further integrating our businesses, optimizing our plant operations and expanding plant and infrastructure.
3. Key Growth Highlights
To achieve corporate strategic objectives and enhance shareholder value and return on investment, we continue to develop opportunities that will drive future growth. Key highlights for the second quarter of 2008, are noted below:
Upstream
Western Canada
Husky obtained approval for its Alkaline Surfactant Polymer ("ASP") project at Gull Lake in southwest Saskatchewan (Husky's share 73.6%). Start up of the project is planned for the second quarter of 2009. This project is designed to increase production and improve the recovery of original oil in place by 15%.
In Lloydminster, Husky commenced commissioning on an additional heavy oil cold enhanced recovery pilot project. This project is designed to test injection of CO2 into the reservoir as a further enhancement to the recovery process. The first cold enhanced recovery pilot project continues to demonstrate positive results.
Drilling at the Trident coal bed methane development (Husky's share 50%) is expected to increase in the second half of the year following an agreement with our partner on cost sharing. Between 100 and 120 new wells are planned for the remainder of 2008.
White Rose Development and Delineation
The North Amethyst tie-back development plan was approved by the federal and provincial governments in April 2008. Procurement of long lead equipment for the North Amethyst field is proceeding on schedule. Additional delineation and reservoir analysis at the West White Rose tie-back project will take place in the second half of 2008 and the development application is progressing as planned. The front-end engineering design for West White Rose is planned to run concurrently with the North Amethyst project execution. The South White Rose extension, the smaller of the satellite tie-back developments, was approved by the federal and provincial governments in September 2007 and is expected to augment production following completion of the North Amethyst and West White Rose tie-back projects.
The semi-submersible drilling rig, Henry Goodrich, is expected to arrive in Newfoundland and Labrador waters in August 2008. The Henry Goodrich will be available for Husky operated wells for 17 months of a total 27-month drilling program. The GSF Grand Banks semi-submersible drilling rig, which has been working at White Rose, has also been contracted for an additional period ending in January 2011. These rigs will drill several development wells in the White Rose and satellite fields, the Terra Nova field as well as exploration prospects in the Jeanne d'Arc Basin.
East Coast Exploration
Husky, together with its partners, commenced a 3-D seismic program covering 2,500 square kilometres over the White Rose and satellite fields, the Terra Nova field and on portions of five exploration licences in the Jeanne d'Arc Basin. This activity is expected to be concluded in the third quarter of 2008 and is expected to identify additional drilling opportunities.
We will participate in the drilling of an exploration well on Exploration Licence ("EL") 1049 in the Flemish Pass Basin off the east coast of Newfoundland and Labrador. Drilling is expected to commence in the fourth quarter of 2008. StatoilHydro is the operator and Husky has a 35% interest in the licence.
Tucker Oil Sands Project
Optimization strategies to resolve start up issues and enhance the ramp-up of production are continuing. Modifications of three wells on Pad A, designed to improve the effectiveness of steam heating of the reservoir, are close to commissioning. Pad C has been expanded with eight new well pairs and steam injection has commenced on six of the eight well pairs. Drilling on the new Pad D is planned for early 2009 and will utilize experience gained from work currently underway on Pads A and C.
Sunrise Oil Sands Project
The development of the Sunrise oil sands project will proceed in multiple phases. The first development phase will produce 60 mbbls/day of bitumen commencing late 2012 and the second and third phases are targeted to increase the Sunrise production capacity to approximately 200 mbbls/day of bitumen by 2015 to 2020, subject to corporate sanction. Work on area infrastructure and site preparation, including roads and pads, progressed on schedule during the second quarter. In addition, detailed design of the facilities commenced and preparation for long lead equipment procurement and construction contracts was initiated.
McMullen Development
Planning for the development of the McMullen property located in the west central region of the Athabasca oil sands of northern Alberta is progressing. Husky plans to develop production through a multi-well drilling program in 2008 using cold production technology similar to that used in the Lloydminster heavy oil operations. Husky also progressed plans to implement a pilot project that will test thermal recovery techniques.
Caribou
The preliminary engineering design of the 10 mbbls/day demonstration project commenced in the second quarter of 2008.
Saleski
Seismic analysis and reservoir studies are proceeding in preparation for the 2009 drilling program.
Offshore China Exploration
On June 25, 2008, Husky announced the acquisition of exploration Block 63/05 covering 1,777 square kilometres located in the natural gas prone Qiondongnan Basin approximately 100 kilometres south of Hainan Island. CNOOC Ltd. has the right to participate in the development of any discoveries up to a 51% working interest. Under the terms of the petroleum contract, we have committed to drill one well and acquire 300 square kilometres of seismic data within a three-year period.
The West Hercules deep water drilling rig is undergoing commissioning and is expected to arrive in the South China Sea in August 2008. The rig will initially drill the second of our planned exploration wells on Block 39/05 which surrounds the Wenchang oil field. Upon completion of this well, the first of four delineation wells is expected to spud in September 2008 at the Liwan natural gas discovery on Block 29/26.
In the second quarter of 2008, we completed a 3-D seismic data program on Blocks 29/26 and 29/06, which surround the Liwan natural gas discovery. Acquisition of 3-D seismic data was also completed on Blocks 35/18 and 50/14, which are located to the west of Hainan Island in the Yinggehai Basin. We are working toward securing a drilling rig for a multi-well program on these two blocks in 2009. The first phase exploration work commitment for these two Yinggehai blocks expires on September 30, 2009.
During the second quarter of 2008, the Wushi 23-2-1 exploration well was abandoned without testing. This well was on Block 23/15 in the Beibu Wan Basin north of Hainan Island in the South China Sea.
Indonesia Exploration and Development
In April 2008, we completed an agreement with CNOOC Ltd. to jointly develop the Madura BD gas and natural gas liquids field located offshore East Java, Indonesia. Under the agreement, CNOOC Ltd. acquired a 50% equity interest and operatorship of Husky Oil (Madura) Limited, which holds a 100% interest in the Madura Strait Production Sharing Contract ("PSC"). The agreement covers the development and further exploration of the Madura Strait PSC. The Madura BD field development plan has been approved by the regulatory authorities and the PSC extension has been submitted for approval. Regulatory authorities are currently reviewing the work plan for the East Bawean II exploration block. Final 3-D seismic data has been delivered and preparatory work for two exploration wells is underway for the 2009 drilling program.
Offshore Greenland
The seismic acquisition vessel, Wavefield Akademic Shatsky, arrived in Nuuk, Greenland in early July, 2008 to perform a 7,000 kilometre 2-D seismic data program on Blocks 5 and 7. Husky is the operator and holds an 87.5% interest in these two blocks. The acquisition of 3,000 kilometres of 2-D seismic is planned for Block 6 later in 2008. We hold a 43.75% interest in this block. A hi-resolution aero-gravity and magnetic survey covering Husky's blocks is approximately 40% complete.
Downstream
Lima, Ohio Refinery
An engineering evaluation has been completed to determine the reconfiguration of the Lima refinery to increase its capacity to process heavier, less costly, crude oil feedstocks; realize complex refining processing margins; and increase flexibility in product outputs. The current configuration at the Lima refinery restricts it to a predominantly light sweet crude oil feedstock. This limits our ability to process a lower cost heavier crude feedstock to meet seasonal and longer term market demands. The results are being evaluated to determine the best approach to achieve the reconfiguration.
BP/Husky Toledo, Ohio Refinery
The acquisition of 50% of the BP/Husky Toledo refinery, which has the capacity to process 150 mbbls/day of crude oil including 60 mbbls/day of blended heavy sour crude oil, closed on March 31, 2008 with an effective date of January 1, 2008. BP and Husky are planning to convert this refinery to process bitumen feedstock in conjunction with their investment in the Sunrise oil sands project.
4. Business Environment
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Average Benchmarks
Three months ended
June 30 March 31
2008 2008
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WTI crude oil (1) (U.S. $/bbl) 123.98 97.90
Brent crude oil (2) (U.S. $/bbl) 121.38 96.90
Canadian light crude 0.3% sulphur ($/bbl) 126.73 98.20
Lloyd heavy crude oil @ Lloydminster
($/bbl) 89.70 64.23
NYMEX natural gas (1) (U.S. $/mmbtu) 10.93 8.03
NIT natural gas ($/GJ) 8.86 6.76
WTI/Lloyd crude blend differential
(U.S. $/bbl) 21.95 21.81
New York Harbor 3:2:1 crack spread
(U.S. $/bbl) 14.50 10.09
U.S./Canadian dollar exchange rate
(U.S. $) 0.990 0.996
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Average Benchmarks
Three months ended
Dec. 31 Sept. 30 June 30 March 31
2007 2007 2007 2007
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WTI crude oil (1) (U.S. $/bbl) 90.68 75.38 65.03 58.16
Brent crude oil (2) (U.S. $/bbl) 88.70 74.87 68.76 57.75
Canadian light crude 0.3% sulphur ($/bbl) 87.19 80.70 72.61 67.76
Lloyd heavy crude oil @ Lloydminster
($/bbl) 42.03 43.61 39.02 38.25
NYMEX natural gas (1) (U.S. $/mmbtu) 6.97 6.16 7.55 6.77
NIT natural gas ($/GJ) 5.69 5.31 6.99 7.07
WTI/Lloyd crude blend differential
(U.S. $/bbl) 34.06 23.50 20.36 17.32
New York Harbor 3:2:1 crack spread
(U.S. $/bbl) 8.23 11.91 24.18 12.32
U.S./Canadian dollar exchange rate
(U.S. $) 1.018 0.957 0.911 0.854
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(1) Prices quoted are near-month contract prices for settlement during the
next month.
(2) Dated Brent prices which are dated less than 15 days prior to loading
for delivery.
Commodity Prices
As an integrated producer, profitability is largely determined by realized prices for crude oil and natural gas and refinery processing margins, including the effect of changes in the U.S./Canadian dollar exchange rate. All of our crude oil production and the majority of our natural gas production receive the prevailing market price. The price for crude oil is determined mainly by global factors and is beyond our control. The price for natural gas is determined primarily by the North America fundamentals since virtually all natural gas production in North America is consumed by North American customers, predominantly in the United States. Weather conditions also have a dramatic effect on short-term supply and demand.
During 2007, the price of WTI averaged U.S. $72/bbl and ended the year at U.S. $96/bbl. In the first quarter of 2008, the price of WTI averaged U.S. $ 98/bbl and ended the quarter at U.S. $102/bbl. During the second quarter of 2008, WTI averaged U.S. $124/bbl and ended the quarter at U.S. $140/bbl.
The steady rise in global crude oil prices over the last 18 months reflects a number of complex issues that are maintaining strong demand and uncertain supply. Chief among those issues are the emergence of new growing economies and their increasing demand for petroleum products, production uncertainties caused by geopolitical tension and uncertainties in respect of surplus productive capacity. The economic downturn in the United States during the first six months of 2008 has only marginally reduced consumption of petroleum in spite of record high fuel prices.
Natural gas prices quoted on the NYMEX rose sharply through the first six months of 2008 and were, on average, 37% higher than the same period in 2007. Higher prices in the first half of 2008 are largely attributed to comparatively colder weather, supply concerns related to facility outages in the Gulf of Mexico, comparatively lower LNG imports and working gas in storage that was lower than five-year averages. At the end of the second quarter of 2008, natural gas inventory in underground storage in the United States was 16% lower than at the same date in 2007 and the NYMEX near month price ended the second quarter of 2008 at U.S. $13.30/mmbtu.
Refinery Crack Spreads
The 3:2:1 crack spread is the key indicator for refining margins since, on average, refinery gasoline output is approximately twice the distillate output. This crack spread is equal to the price of two-thirds of a barrel of gasoline plus one-third of a barrel of diesel (distillate) less one barrel of crude oil. Prices are based on NYMEX near month contract averages.
During the second quarter of 2008, the U.S. New York Harbor crack spread improved compared with the first quarter of 2008 as global markets for distillate tightened and U.S. refiners shifted their yield to favour distillate production.
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 2008. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.
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Sensitivity Analysis 2008 Second
Quarter
Average Increase
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Upstream and Midstream
WTI benchmark crude oil price $ 123.98 U.S. $1.00/bbl
NYMEX benchmark natural gas
price (1) $ 10.93 U.S. $0.20/mmbtu
WTI/Lloyd crude blend
differential (2) $ 21.95 U.S. $1.00/bbl
Downstream
Light oil margins $ 0.06 Cdn $0.005/litre
Asphalt margins $ 10.80 Cdn $1.00/bbl
New York Harbor 3:2:1
crack spread (3) $ 14.50 U.S. $1.00/bbl
Consolidated
Exchange rate (U.S. $ per Cdn $) (4) $ 0.990 U.S. $0.01
Interest rate 100 basis points
Period end translation
of U.S. $ debt (U.S. $ per Cdn $) $ 0.982 (5) U.S. $0.01
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Sensitivity Analysis
Effect on Annual Pre-tax Effect on Annual
Cash Flow (6) Net Earnings (6)
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($ millions) ($/share)(7) ($ millions) ($/share)(7)
Upstream and Midstream
WTI benchmark crude
oil price 73 0.09 52 0.06
NYMEX benchmark
natural
gas price (1) 25 0.03 18 0.02
WTI/Lloyd crude blend
differential (2) (17) (0.02) (13) (0.01)
Downstream
Light oil margins 14 0.02 9 0.01
Asphalt margins 8 0.01 5 0.01
New York Harbor 3:2:1
crack spread (3) 71 0.08 45 0.05
Consolidated
Exchange rate (U.S. $
per Cdn $) (4) (108) (0.13) (72) (0.08)
Interest rate (10) (0.01) (7) (0.01)
Period end translation
of U.S. $ debt
(U.S. $ per Cdn $) - - 13 0.02
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(1) Includes decrease in net earnings related to natural gas consumption.
(2) Includes impact of upstream and upgrading operations only.
(3) Relates to U.S. Refining & Marketing.
(4) Assumes no foreign exchange gains or losses on U.S. dollar denominated
long-term debt and other monetary items.
(5) U.S./Canadian dollar exchange rate at June 30, 2008.
(6) Excludes derivatives.
(7) Based on 849.1 million common shares outstanding as of June 30, 2008.
5. Results of Operations
5.1 Upstream
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Upstream Net Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
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Gross revenues $ 3,081 $ 1,828 $ 5,334 $ 3,591
Royalties 657 235 1,081 433
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Net revenues 2,424 1,593 4,253 3,158
Operating and administration
expenses 409 344 793 667
Depletion, depreciation and
amortization 352 407 742 806
Other (81) (49) (52) (49)
Income taxes 505 255 814 518
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Net earnings $ 1,239 $ 636 $ 1,956 $ 1,216
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Net Revenue
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Upstream Revenue Mix Three months Six months
ended June 30 ended June 30
Percentage of upstream
net revenues 2008 2007 2008 2007
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Crude oil & NGL
Light crude oil & NGL 40 53 42 52
Medium crude oil 8 6 8 6
Heavy crude oil & bitumen 31 20 30 20
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Total crude oil & NGL 79 79 80 78
Natural gas 21 21 20 22
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100 100 100 100
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Pricing
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Average Sales Prices Realized Three months Six months
ended June 30 ended June 30
2008 2007 2008 2007
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Crude Oil ($/bbl)
Light crude oil
& NGL $ 121.71 $ 72.28 $ 108.64 $ 68.28
Medium crude oil 101.87 48.15 88.13 47.26
Heavy crude oil &
bitumen 89.35 38.19 76.69 37.91
Total average 106.29 56.99 93.26 54.68
Natural Gas ($/mcf)
Average 9.14 6.91 8.11 6.92
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Second Quarter
During the second quarter of 2008, upstream net revenues increased by $831 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower crude oil sales volumes and higher royalties.
During the second quarter of 2008, our realized heavy crude oil prices averaged 72% of our realized light crude oil prices versus 52% during the same period in 2007.
Six Months
For the six months ended June 30, 2008, upstream net revenues increased by $1,095 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower crude oil and natural gas sales volumes and higher royalties.
During the first six months of 2008, our realized heavy crude oil prices averaged 69% of our realized light crude oil prices versus 55% during the same period in 2007.
Oil and Gas Production
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Daily Gross Production Three months Six months
ended June 30 ended June 30
2008 2007 2008 2007
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Crude oil & NGL (mbbls/day)
Western Canada
Light crude oil & NGL 24.0 25.3 24.7 27.6
Medium crude oil 27.0 26.8 27.0 27.2
Heavy crude oil & bitumen 105.5 105.4 104.9 106.7
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156.5 157.5 156.6 161.5
East Coast Canada
White Rose - light
crude oil 75.6 90.3 71.6 89.9
Terra Nova - light
crude oil 12.5 15.5 13.7 15.0
China
Wenchang - light crude
oil & NGL 11.5 13.2 12.1 13.5
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Total crude oil & NGL 256.1 276.5 254.0 279.9
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Natural gas (mmcf/day) 618.0 615.7 604.2 627.8
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Total (mboe/day) 359.1 379.1 354.7 384.6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crude Oil and NGL Production
Second Quarter
In the second quarter of 2008, crude oil and NGL production decreased by 7% compared with the same period in 2007. Production from the White Rose field was shut down for 11 days in April as a result of ice encroachment due to severe ice pack and iceberg conditions. Production from White Rose averaged 76 mbbls/day during the second quarter of 2008 compared with 90 mbbls/day during the same period in 2007.
In June 2008, Terra Nova was shut down for 14 days for a scheduled maintenance turnaround that was originally planned to take place in July.
Six Months
In the first half of 2008, crude oil and NGL production decreased by 9% compared with the same period of the previous year. In addition to the issues impacting the second quarter, White Rose production was reduced by a 13-day turnaround for scheduled maintenance of the SeaRose FPSO during the first quarter of 2008. This maintenance turnaround was originally scheduled for August.
During the first half of 2008, crude oil and NGL production from Western Canada was down 3% compared with the first half of 2007, primarily due to the disposition of non-core oil properties.
Natural Gas Production
Second Quarter
Production of natural gas was marginally higher in the second quarter of 2008 compared with the same period in 2007. During the second quarter of 2008, new natural gas wells tied-in offset normal reservoir declines and reduced production resulting from turnarounds.
In the second quarter of 2008, 60% of our natural gas production was from the foothills of Alberta and British Columbia, the deep basin of Alberta and the plains of northeast British Columbia and northwest Alberta; the remainder was from the plains throughout Alberta and southwest Saskatchewan.
Six Months
During the first half of 2008, natural gas production was 4% lower than the year before due to severe cold weather in Western Canada in the first quarter and reduced drilling activity in 2007 in response to low natural gas prices and pending higher Alberta gas royalties. This was offset by higher second quarter production as discussed above.
Production Guidance
----------------------------------------------------------------------------
2008 Gross Production Guidance Six months Year ended
Guidance ended June 30 Dec. 31
2008 2008 2007
----------------------------------------------------------------------------
Crude oil & NGL (mbbls/day)
Light crude oil & NGL 139 - 148 122 139
Medium crude oil 28 - 29 27 27
Heavy crude oil & bitumen 114 - 124 105 107
----------------------------------------------------------------------------
281 - 301 254 273
Natural gas (mmcf/day) 625 - 655 604 623
Total barrels of oil
equivalent (mboe/day) 385 - 410 355 377
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Following the completion of the turnarounds at White Rose and Terra Nova in the first half of 2008, crude oil production is expected to increase from current levels in the second half of the year. However, the severe ice conditions which suspended production at White Rose during the first half of the year and the ramp-up of production at the Tucker Oil Sands project will impact our annual production. Production for 2008 is now expected to be five to seven percent below our guidance range.
Royalties
In the second quarter of 2008, royalty rates in Western Canada averaged 16% as a percentage of gross revenue, unchanged from the second quarter of 2007.
In March 2008, the Tier II incremental royalty rate became effective for White Rose. East coast offshore royalty rates averaged 31% as a percentage of gross revenue in the second quarter compared with 8% in the second quarter of 2007.
Royalty rates for the first six months of 2008 averaged 16% in Western Canada and 28% offshore east coast compared with 16% and 6% in 2007.
Unit Operating Costs
Second Quarter
In the second quarter of 2008, operating costs in Western Canada averaged $12.95/boe compared with $11.10/boe in the same period in 2007. Increasing operating costs in Western Canada are generally related to the nature of exploitation necessary to manage production from maturing fields and new more extensive but less prolific reservoirs. Western Canada operations require increasing amounts of infrastructure including more wells, facilities associated with enhanced recovery schemes, more extensive pipeline systems, crude and water trucking and more extensive natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. In addition, higher levels of industry activity lead naturally to competition for resources and consequential higher service rates and unit costs. Our efforts are focused on managing rising operating costs with initiatives such as the establishment of a logistics support division to control costs of transporting production. We strive to keep our infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure fully utilized.
Operating costs at the East Coast offshore operations averaged $5.47/bbl in the second quarter of 2008 compared with $4.00/bbl in the second quarter of 2007. The higher unit operating cost in 2008 was due to lower production volume. Operating costs in total were $5 million higher in the second quarter of 2008 compared with 2007 due to additional resources required to manage ice encroachment and subsurface mechanical issues. Operating costs at the South China Sea offshore operations averaged $5.19/bbl in the second quarter of 2008 compared with $3.04/bbl in the same period in 2007 as a result of higher maintenance costs.
Six Months
Total upstream operating costs in the first half of 2008 increased by 17% over 2007. In addition to the factors affecting the second quarter, operating costs were adversely affected in the first quarter by extreme cold weather in Western Canada, which resulted in increased costs for gas well servicing and methanol injection to deal with gas well freeze ups and the scheduled turnaround of the Sea Rose FPSO.
Unit Depletion, Depreciation and Amortization
Second Quarter
Total unit DD&A averaged $10.78/boe in the second quarter of 2008 compared with $11.79/boe in the second quarter of 2007. In Canada, unit DD&A was $10.81/boe, a decrease of 8% over the second quarter of 2007. The lower DD&A rate in Canada was primarily due to the disposition of 50% of the Sunrise oil sands asset, which reduced the full cost base by approximately $1.8 billion or $1.90/boe in the second quarter of 2008. The Sunrise oil sands project currently does not have any proved reserves attributed to it.
Six Months
For the first six months of 2008 total unit DD&A averaged $11.50/boe compared with $11.58/boe during the same period in 2007 primarily due to the effect of the Sunrise disposition largely offset by a higher full cost base in the first quarter of 2008 compared with the first half of 2007.
----------------------------------------------------------------------------
Netback Analysis Three months Six months
ended June 30 ended June 30
2008 2007 2008 2007
----------------------------------------------------------------------------
$ $ $ $
Total
Crude oil equivalent (per boe) (1)
Gross price 91.53 52.56 80.60 51.10
Royalties 19.77 6.81 16.52 6.21
----------------------------------------------------------------------------
Net sales price 71.76 45.75 64.08 44.89
Operating costs (2) 10.91 8.84 10.83 8.59
----------------------------------------------------------------------------
Operating netback 60.85 36.91 53.25 36.30
DD&A 10.78 11.79 11.50 11.58
Administration expenses and
other (2) (3.30) (0.71) (1.17) (0.19)
----------------------------------------------------------------------------
Earnings before income taxes 53.37 25.83 42.92 24.91
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Western Canada
Crude oil (per boe) (1)
Light crude oil
Gross price 99.68 59.41 88.70 58.08
Royalties 13.61 6.32 11.88 6.26
----------------------------------------------------------------------------
Net sales price 86.07 53.09 76.82 51.82
Operating costs (2) 14.17 13.89 15.29 12.82
----------------------------------------------------------------------------
Operating netback 71.90 39.20 61.53 39.00
----------------------------------------------------------------------------
Medium crude oil
Gross price 99.28 47.81 85.87 46.99
Royalties 17.71 8.38 15.48 8.17
----------------------------------------------------------------------------
Net sales price 81.57 39.43 70.39 38.82
Operating costs (2) 16.23 12.48 15.36 13.03
----------------------------------------------------------------------------
Operating netback 65.34 26.95 55.03 25.79
----------------------------------------------------------------------------
Heavy crude oil & bitumen
Gross price 88.74 38.30 76.19 37.98
Royalties 12.17 4.97 10.21 4.84
----------------------------------------------------------------------------
Net sales price 76.57 33.33 65.98 33.14
Operating costs (2) 15.91 12.96 15.43 12.40
----------------------------------------------------------------------------
Operating netback 60.66 20.37 50.55 20.74
----------------------------------------------------------------------------
Natural gas (per mcfge) (3)
Gross price 9.52 7.04 8.51 7.03
Royalties 1.86 1.37 1.65 1.41
----------------------------------------------------------------------------
Net sales price 7.66 5.67 6.86 5.62
Operating costs (2) 1.43 1.35 1.49 1.34
----------------------------------------------------------------------------
Operating netback 6.23 4.32 5.37 4.28
----------------------------------------------------------------------------
East Coast
Light crude oil (per boe) (1)
Gross price 124.72 73.79 111.74 70.17
Royalties (4) 38.89 6.04 31.62 4.10
----------------------------------------------------------------------------
Net sales price 85.83 67.75 80.12 66.07
Operating costs (2) 5.47 4.00 5.37 3.52
----------------------------------------------------------------------------
Operating netback 80.36 63.75 74.75 62.55
----------------------------------------------------------------------------
International
Light crude oil (per boe) (1)
Gross price 131.62 75.14 115.39 71.65
Royalties 36.99 14.43 31.55 12.36
----------------------------------------------------------------------------
Net sales price 94.63 60.71 83.84 59.29
Operating costs (2) 5.19 3.04 4.90 3.98
----------------------------------------------------------------------------
Operating netback 89.44 57.67 78.94 55.31
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes associated co-products converted to boe.
(2) Operating costs exclude accretion, which is included in administration
expenses and other.
(3) Includes associated co-products converted to mcfge.
(4) During March 2008, White Rose royalties achieved payout status for Tier
2 royalties.
Other Items
During the second quarter of 2008, an $11 million gain was recorded on an embedded derivative related to a drilling rig contract requiring payment in U.S. currency compared with a $49 million gain in the second quarter of 2007. A loss of $17 million was recorded in the first six months of 2008 compared with a gain of $49 million for the same period in 2007. The payments are expected to occur over the three-year period from mid-2008. The amount will fluctuate with the U.S./Cdn forward exchange rate until actual contract settlement. Contracts to purchase U.S. currency have been entered into which offset approximately 60% of this derivative. (Refer to Note 16 to the Consolidated Financial Statements).
Other items also include a gain of $69 million on the sale of 50% of Husky Oil (Madura) Limited to CNOOC Ltd. in the second quarter of 2008.
Upstream Capital Expenditures
By the end of the first half of 2008, overall upstream capital expenditures were 47% of the 2008 capital expenditure guidance. Delays are related to semi-submersible drilling rig delivery dates, contracting for consulting engineering services and receiving regulatory approvals. Our major upstream projects remain on schedule and their ultimate completion dates are expected to be maintained.
----------------------------------------------------------------------------
Three months Six months
Capital Expenditures Summary (1) ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Exploration
Western Canada $ 103 $ 76 $ 309 $ 241
East Coast Canada and Frontier 20 - 45 5
International 32 20 62 25
----------------------------------------------------------------------------
155 96 416 271
----------------------------------------------------------------------------
Development
Western Canada 394 357 863 745
East Coast Canada 73 62 141 116
International 3 5 3 5
----------------------------------------------------------------------------
470 424 1,007 866
----------------------------------------------------------------------------
$ 625 $ 520 $ 1,423 $ 1,137
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized costs related to asset retirement obligations
incurred during the period.
During the first six months of 2008, capital expenditures were $1,172 million (82%) in Western Canada, $186 million (13%) off the East Coast of Canada and $65 million (5%) offshore China and Indonesia.
The following table discloses the number of gross and net exploration and development wells we completed in Western Canada and the oil sands during the periods indicated. All of the net exploration wells and net development wells we drilled in the second quarter of 2008 resulted in wells capable of commercial production.
----------------------------------------------------------------------------
Western Canada and Oil Sands Three months Six months
Wells Drilled ended June 30 ended June 30
2008 2007 2008 2007
Gross Net Gross Net Gross Net Gross Net
----------------------------------------------------------------------------
Exploration Oil 5 3 13 13 28 26 33 33
Gas 7 4 4 3 64 53 69 59
Dry - - 1 1 20 19 10 10
----------------------------------------------------------------------------
12 7 18 17 112 98 112 102
----------------------------------------------------------------------------
Development Oil 73 73 58 54 193 177 196 184
Gas 19 17 6 4 135 104 174 141
Dry - - 2 2 3 3 12 12
----------------------------------------------------------------------------
92 90 66 60 331 284 382 337
----------------------------------------------------------------------------
Total 104 97 84 77 443 382 494 439
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Western Canada - Excluding Oil Sands
During the first six months of 2008, we invested $994 million on exploration and development in Western Canada excluding oil sands, which produces variously light, medium, heavy crude oil or natural gas throughout the Western Canada Sedimentary Basin. Of this, $527 million was invested on properties in Alberta, northeast British Columbia and southern Saskatchewan primarily to further develop and extend properties with proved reserves. We drilled 382 net wells in these regions during the first six months of 2008, resulting in 203 net oil wells and 144 net natural gas wells. In the Lloydminster area of Alberta and Saskatchewan, from which the majority of our heavy crude oil is produced, we invested $388 million in this same period, to extend proved properties, implement cost reduction initiatives and perform engineering studies in respect of improved recovery schemes.
Our high impact exploration program is conducted along the foothills of Alberta and British Columbia and in the deep basin region of Alberta. In the first six months of 2008, we invested $79 million drilling in these natural gas prone areas. During the first six months of 2008, we drilled 15 net exploration wells in the foothills/deep basin regions; 13 were cased as natural gas wells. The remaining 83 net exploration wells were drilled primarily in the shallow regions of the Western Canada Sedimentary Basin.
Oil Sands
Oil sands capital expenditures totaled $178 million during the first six months of 2008. At Tucker, we spent $63 million on drilling new well pairs, facility modification and new pad preparation. At Sunrise, we spent $84 million on engineering design, site preparation and facilities and equipment requisitions. At Caribou and Saleski we spent $31 million on project development.
East Coast Development
During the first half of 2008, we spent $141 million primarily for SeaRose FPSO tie-back projects and White Rose capital enhancements. Construction commenced on North Amethyst long lead equipment, engineering design began for the West White Rose development and infill drilling commenced at the White Rose South Avalon field.
East Coast and Northwest Territories Exploration
During the first half of 2008, we spent $45 million on two exploration wells in the Central Mackenzie Valley and on preliminary planning for our East Coast seismic program.
International
During the first half of 2008, we spent $62 million on exploration drilling in the South China Sea and seismic on the East Bawean II exploration block in the Java Sea.
2008 Guidance
Our 2008 Upstream Capital expenditure guidance remains unchanged from that reported in our 2007 annual MD&A.
----------------------------------------------------------------------------
2008 Capital Expenditure Guidance (1)
(millions of dollars)
----------------------------------------------------------------------------
Western Canada - oil & gas $ 1,670
- oil sands 300
East Coast Canada 650
International 430
----------------------------------------------------------------------------
$ 3,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes capitalized administrative costs and capitalized interest.
5.2 Midstream
----------------------------------------------------------------------------
Upgrading Net Earnings Summary Three months Six months
ended June 30 ended June 30
(millions of dollars, except where
indicated) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross margin $ 168 $ 89 $ 339 $ 227
Operating and administration expenses 67 47 130 105
Other recoveries (1) (1) (2) (2)
Depreciation and amortization 7 4 13 10
Income taxes 28 10 59 34
----------------------------------------------------------------------------
Net earnings $ 67 $ 29 $ 139 $ 80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Upgrader throughput (1) (mbbls/day) 58.5 36.1 60.7 52.5
Synthetic crude oil sales (mbbls/day) 51.6 32.9 53.6 45.3
Upgrading differential ($/bbl) $ 30.12 $ 30.41 $ 29.28 $ 26.42
Unit margin ($/bbl) $ 35.61 $ 29.74 $ 34.69 $ 27.64
Unit operating cost (2) ($/bbl) $ 12.53 $ 14.37 $ 11.73 $ 11.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Throughput includes diluent returned to the field.
(2) Based on throughput.
The upgrading business segment adds value by processing heavy sour crude oil into high value synthetic crude oil and low sulphur distillates. The upgrader profitability is primarily dependent on the differential between the cost of the heavy crude feedstock and the sales price of the synthetic crude oil.
Second Quarter
During the second quarter of 2008, the upgrading differential averaged $30.12/bbl, marginally lower than a year earlier. The differential is equal to Husky Synthetic Blend, which sells at a premium to West Texas Intermediate, less Lloyd Heavy Blend. During the second quarter of 2008, the overall unit margin was 20% higher than a year earlier partly due to the addition of low sulphur off-road diesel to the upgrader's product stream.
Upgrader throughput was 62% higher in the second quarter of 2008 compared with the same period in 2007. Throughput was low during the second quarter of 2007 due to a 49-day scheduled turnaround and installation of new coke drums. Throughput was below capacity during the second quarter of 2008 due to a temporary shutdown to replace the hydrogen plant catalyst. Unit operating costs decreased by 13% in the second quarter of 2008 compared with a year earlier as a result of higher throughput which increased at a higher rate than increases in total operating costs. Operating cost increases were mainly attributable to higher energy costs.
Six Months
During the first half of 2008, upgrading earnings were 74% higher than the year earlier, primarily due to the same factors that affected the second quarter.
----------------------------------------------------------------------------
Infrastructure and Marketing Net Three months Six months
Earnings Summary ended June 30 ended June 30
(millions of dollars, except where
indicated) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross margin - pipeline $ 44 $ 28 $ 69 $ 54
- other infrastructure
and marketing 90 48 179 120
----------------------------------------------------------------------------
134 76 248 174
Operating and administration expenses 4 - 7 4
Depreciation and amortization 7 7 15 14
Income taxes 37 21 68 48
----------------------------------------------------------------------------
Net earnings $ 86 $ 48 $ 158 $ 108
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Aggregate pipeline throughput
(mbbls/day) 539 506 521 500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Second Quarter
Infrastructure and marketing net earnings in the second quarter of 2008 were $86 million compared with $48 million in the second quarter of 2007. Higher earning were primarily due to higher pipeline throughput and tariffs and higher brokering margins on crude oil and sulphur.
Six Months
During the first half of 2008, infrastructure and marketing earnings were 46% higher than the year earlier primarily because of the same factors that affected the second quarter of 2008.
Midstream Capital Expenditures
Midstream capital expenditures totalled $65 million in the first six months of 2008: $51 million was spent at the Lloydminster upgrader, primarily for contingent consideration and facility reliability projects. The remaining $14 million was spent on the pipeline extension between Lloydminster and Hardisty, Alberta.
5.3 Downstream
----------------------------------------------------------------------------
Canadian Refined Products Net Three months Six months
Earnings Summary ended June 30 ended June 30
(millions of dollars, except where
indicated) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross margin - fuel sales $ 50 $ 63 $ 88 $ 105
- ancillary sales 14 10 24 19
- asphalt sales 28 36 47 49
----------------------------------------------------------------------------
92 109 159 173
Operating and administration expenses 22 20 26 38
Depreciation and amortization 20 15 40 31
Income taxes 15 21 28 31
----------------------------------------------------------------------------
Net earnings $ 35 $ 53 $ 65 $ 73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected
operating data:
Number of fuel
outlets 498 504
Light oil sales (million litres/day) 7.9 8.6 7.9 8.8
Light oil retail
sales per
outlet (thousand litres/day) 12.6 13.3 12.9 12.8
Prince George
refinery
throughput (mbbls/day) 10.5 8.4 11.0 9.7
Asphalt sales (mbbls/day) 23.0 19.5 20.4 18.4
Lloydminster
refinery
throughput (mbbls/day) 26.4 18.5 24.2 21.6
Ethanol
production (thousand litres/day) 600.1 305.9 624.6 313.7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Canadian Refined Products
Second Quarter
During the second quarter of 2008, we benefited from higher throughput at the Prince George refinery, which produces a high gasoline yield. However, earnings from sales of gasoline and diesel were lower than a year earlier due to lower sales volume and slightly lower margins. Sales volumes were down as a result of supply shortages from our third party refined product suppliers due to refinery outages. Ancillary income from convenience store and restaurant sales continues to grow.
Second quarter 2008 ethanol production increased 96% due to the start-up of the Minnedosa ethanol plant, which commenced operations at the end of 2007. This was offset by a 68% reduction in margins in 2008 due to the run up of corn prices, reduced demand and increases in natural gas prices.
During the second quarter of 2008, asphalt product margins were approximately 42% lower than a year earlier, partially offset by increased sales volumes. Asphalt margins were impacted by the increase in heavy crude oil feedstock costs. Additional value was captured in the quarter from higher volumes of residuals and distillates produced at the Lloydminster refinery and processed at the Lloydminster upgrader into low sulphur off-road diesel and synthetic crude oil.
Six Months
During the first half of 2008, earnings from gasoline and diesel were lower than the same period of 2007 as a result of the same factors affecting the second quarter. Earnings from ethanol sales were higher than the previous year as higher sales volume more than offset lower unit margins. Margins on asphalt products were lower than the same period in the previous year due to rising crude oil feedstock costs.
----------------------------------------------------------------------------
U.S. Refining and Marketing Net Three months Six months
Earnings Summary ended June 30 ended June 30
(millions of dollars, except where indicated) 2008 2008
----------------------------------------------------------------------------
Gross refining margin $ 398 $ 485
Processing costs 106 159
Operating and administration expenses 1 2
Interest - net - 1
Depreciation and amortization 43 62
Income taxes 89 94
----------------------------------------------------------------------------
Net earnings $ 159 $ 167
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Selected operating data:
Lima refinery throughput (mbbls/day) 144.1 141.2
Toledo refinery throughput (mbbls/day) 66.0 66.0 (1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Toledo refinery operating results are included from March 31, 2008,
the date the acquisition was completed. Throughput represents three
months of operations.
U.S. Refining and Marketing
The U.S. Refining and Marketing segment commenced operations on July 1, 2007 with the acquisition of the Lima, Ohio refinery. The Lima refinery has a crude oil throughput capacity of 160 mbbls/stream day.
On March 31, 2008, we completed a transaction that resulted in the formation of two joint entities forming an integrated oil sands business. The downstream entity is a 50% interest in the BP Toledo refinery, which has a crude distillation capacity of 150 mbbls/day. The transaction was effective January 1, 2008 and the results of its operations for the first quarter of 2008 were reflected as an adjustment to the value assigned to the refinery assets transferred to the downstream entity on March 31, 2008. The second quarter of 2008 is the first period that the BP/Husky Toledo refinery's results of operations have been reflected in our earnings.
In the downstream sector, the drop in demand for motor fuels that began in mid-2007 continued through the first half of 2008, in line with U.S. economic conditions and record high fuel prices. Lower consumption combined with higher product stocks resulted in narrow refinery crack spreads. Crack spreads improved in the second quarter primarily on distillates, which were in high demand globally.
Downstream Capital Expenditures
Downstream capital expenditures totalled $88 million during the first six months of 2008. Capital spending was primarily related to various environmental protection and reliability upgrades at our refineries and plants and for marketing location upgrades and construction.
5.4 Corporate
----------------------------------------------------------------------------
Corporate Summary Three months Six months
ended June 30 ended June 30
(millions of dollars) income (expense) 2008 2007 2008 2007
----------------------------------------------------------------------------
Intersegment eliminations - net $ (128) $ (33) $ (137) $ (58)
Administration expenses (139) (55) (90) (93)
Depreciation and amortization (7) (7) (14) (12)
Interest - net (41) (22) (86) (43)
Foreign exchange (6) 36 (16) 37
Income taxes 98 36 108 63
----------------------------------------------------------------------------
Net earnings (loss) $ (223) $ (45) $ (235) $ (106)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Intersegment eliminations are profit included in inventory that has not been sold to third parties at the end of the period.
In the second quarter of 2008, administration expenses included stock-based compensation expense of $114 million compared with $43 million in the same period in 2007. The increase in net interest expense during the second quarter of 2008 compared with a year earlier was primarily due to a higher level of debt. Additional debt was issued during 2007 for the acquisition of the Lima refinery.
----------------------------------------------------------------------------
Foreign Exchange Summary Three months Six months
ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
----------------------------------------------------------------------------
Unrealized (gain) loss
on translation of U.S.
dollar denominated
long-term debt $ (10) $ (101) $ 34 $ (115)
Cross currency swaps 3 32 (11) 36
Contribution receivable 11 - 11 -
Other (gains) losses 2 33 (18) 42
----------------------------------------------------------------------------
$ 6 $ (36) $ 16 $ (37)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
U.S./Canadian dollar
exchange rates:
At beginning of period U.S. $0.973 U.S. $0.867 U.S. $1.012 U.S. $0.858
At end of period U.S. $0.982 U.S. $0.940 U.S. $0.982 U.S. $0.940
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Corporate Capital Expenditures
Corporate capital expenditures totaled $26 million in the first six months of 2008 primarily for office and information system upgrades.
Consolidated Income Taxes
During the second quarter of 2008, consolidated income taxes consisted of $234 million of current taxes and $342 million of future taxes compared with current taxes of $66 million and future taxes of $205 million in the same period of 2007. The increase in current taxes in the second quarter of 2008 compared with the second quarter of 2007 was due to the deferral of White Rose income in 2007. The increase in future taxes in the second quarter of 2008 compared with the same period in 2007 was due to an increase in earnings.
6. Liquidity and Capital Resources
During the second quarter of 2008, cash flow from operating activities financed all of our capital requirements, dividend payment and repayment of debt. At June 30, 2008 we had $1.5 billion in unused committed credit facilities.
----------------------------------------------------------------------------
Cash Flow Summary Three months Six months
ended June 30 ended June 30
(millions of dollars, except ratios) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash flow - operating activities $ 2,054 $ 1,136 $ 3,281 $ 1,808
- financing activities $(1,217) $ (454) $(1,318) $ (676)
- investing activities $ (667) $ (549) $(1,635) $ (1,441)
Financial Ratios
Debt to capital employed (percent) 13.8 12.1
Corporate reinvestment ratio
(percent) (1) (2) 78 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated for the 12 months ended for the dates shown.
(2) Reinvestment ratio is based on net capital expenditures including
corporate acquisitions.
6.1 Operating Activities
In the second quarter of 2008, cash generated from operating activities amounted to $2.1 billion compared with $1.1 billion in the second quarter of 2007. Higher cash flow from operating activities was primarily due to higher upstream commodity prices, the introduction of the operations of the Lima and Toledo refineries, higher upgrading throughput and unit margin, higher crude oil and sulphur brokering income, higher pipeline throughput and tariffs partially offset by higher cost of sales and operating and administrative expenses, cash taxes and interest.
6.2 Financing Activities
In the second quarter of 2008, cash used in financing activities was $1,217 million compared with $454 million in the second quarter of 2007. The debt issuances and repayments presented in the Consolidated Statements of Cash Flows include multiple drawings and repayments under revolving debt facilities. The remaining bridge financing of $741 million in respect of the acquisition of the Lima refinery was repaid in June 2008.
6.3 Investing Activities
In the second quarter of 2008, cash used in investing activities amounted to $667 million compared with $549 million in the second quarter of 2007. Cash invested in both periods was used primarily for capital expenditures.
6.4 Sources of Capital
We are currently able to fund our capital programs principally by cash provided from operating activities. We also maintain access to sufficient capital via debt markets commensurate with the strength of our balance sheet and continually examine our options with respect to sources of long and short-term capital resources.
Working capital is the amount by which current assets exceed current liabilities. At June 30, 2008, our working capital was $1,488 million compared with a working capital deficiency of $51 million at December 31, 2007. In addition to increases in cash balances, working capital increased due to higher feedstock and refined product inventories, higher accounts receivable at our U.S. refining operations and higher accounts receivable for our Canadian crude oil production. The higher working capital from cash, accounts receivable and inventories was partially offset by higher accounts payable, primarily for U.S. refinery feedstock purchases.
----------------------------------------------------------------------------
June 30 Dec. 31
(millions of dollars) 2008 2007 Change
----------------------------------------------------------------------------
Current assets
Cash and cash equivalents $ 536 $ 208 $ 328 Strong earnings, sale
of 50% of Madura PSC
Accounts receivable 2,171 1,622 549 Higher crude oil prices
Inventories 1,889 1,190 699 Inclusion of Toledo
inventory; increased
Lima inventory
Prepaid expenses 66 28 38 Certain 2008 expenses
paid early in the year
---------------------------------------------------
4,662 3,048 1,614
Current liabilities
Accounts payable 1,847 1,460 (387) Higher crude oil and
gas prices; higher
royalties; inclusion
of Toledo refinery
Accrued interest payable 32 20 (12)
Income taxes payable 214 36 (178) Higher taxable income
Other accrued liabilities 852 842 (10)
Long-term debt due within Repayment of bridge
one year 229 741 512 financing offset by
capital securities
reclassed to current
---------------------------------------------------
3,174 3,099 (75)
---------------------------------------------------
Working capital $1,488 $ (51) $1,539
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Structure
June 30, 2008
(millions of dollars) Outstanding Available
----------------------------------------------------------------------------
Total short-term and long-term debt $ 2,129 $ 1,588
Common shares, retained earnings and
accumulated other comprehensive income $ 13,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
At June 30, 2008, we had unused committed long and short-term borrowing credit facilities totalling $1.5 billion. A total of $82 million of our borrowing credit facilities were used in support of outstanding letters of credit and an additional $44 million of letters of credit were outstanding at June 30, 2008 supported by dedicated letters of credit lines.
The Sunrise Oil Sands Partnership has an unsecured demand credit facility available of $10 million for general purposes. Our proportionate share is $5 million.
We currently have a shelf prospectus dated September 21, 2006 that enables us to offer up to U.S. $1.0 billion of debt securities in the United States until October 21, 2008. During the period that the prospectus is effective, debt securities may be offered in amounts, at prices and on terms to be determined based on market conditions at the time of sale. As of the date of this MD&A, U.S. $750 million of debt securities had been issued under this shelf prospectus and the remaining amount of U.S. $250 million is eligible for issue.
On June 12, 2008, we initiated a cash tender offer to purchase any and all of the 8.90% capital securities. As of June 12, 2008, there were U.S. $225 million of capital securities outstanding. The tender offer expired on July 11, 2008 at which date U.S. $ 214 million or 95% of the capital securities had been tendered. The settlement date occurred July 11, 2008. The remaining capital securities will be redeemed on August 14, 2008.
6.5 Credit Ratings
On March 31, 2008, DBRS upgraded our Senior Unsecured Notes and Debentures to A (low) and our Capital Securities to BBB (high) both with stable trends.
Our other credit ratings are available in our recently filed Annual Information Form at www.sedar.com.
6.6 Contractual Obligations and Commercial Commitments
Refer to Husky's 2007 annual and first quarter 2008 MD&A under the caption "Liquidity and Capital Resources," which summarizes contractual obligations and commercial commitments.
6.7 Off Balance Sheet Arrangements
We do not utilize off balance sheet arrangements with unconsolidated entities to enhance perceived liquidity.
We engage, in the ordinary course of business, in the securitization of accounts receivable. At June 30, 2008 and December 31, 2007, we had no accounts receivable sold under the securitization program. The securitization program permits the sale of a maximum of $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.
6.8 Transactions with Related Parties
TransAlta Power, L.P. is an indirect subsidiary of Cheung Kong Infrastructure Holdings Ltd., which is majority owned by Hutchison Whampoa Limited, which owns 100% of U.F. Investments (Barbados) Ltd., a 34.58% shareholder in Husky. TransAlta Power, L.P. is a 49.99% owner of TransAlta Cogeneration, L.P., our partner in the Meridian cogeneration plant in Lloydminster, Saskatchewan. We sell natural gas to the Meridian cogeneration plant and other cogeneration plants owned by TransAlta Power, L.P. We received the market price or negotiated medium-term contracts based on market-related terms for these commodities. During the first six months of 2008, we sold $64 million of natural gas to TransAlta Power, L.P.
7. Risk Management
Husky is exposed to market risks and various operational risks. For a detailed discussion of these risks see our 2007 Annual Information Form filed on the Canadian Securities Administrator's web site, www.sedar.com, the Securities Exchange Commission's web site, www.sec.gov or our web site www.huskyenergy.com.
Our financial risks are largely related to commodity prices, exchange rates, interest rates, credit risk, changes in fiscal policy related to royalties and taxes and others. From time to time, we use financial and derivative instruments to manage our exposure to these risks.
Interest Rate Risk Management
In the first six months of 2008, interest rate risk management activities resulted in a decrease to interest expense of less than $1 million.
Husky has interest rate swaps on $200 million of long-term debt effective February 8, 2002 whereby 6.95% was swapped for CDOR + 175 bps until July 14, 2009. During the first six months of 2008, these swaps resulted in an offset to interest expense amounting to $1 million.
The amortization of previous interest rate swap terminations resulted in an additional $1 million offset to interest expense in the first six months of 2008.
Cross currency swaps resulted in an addition to interest expense of $2 million in the first six months of 2008.
Foreign Currency Risk Management
At June 30, 2008, we had the following cross currency debt swaps in place:
- U.S. $150 million at 6.25% swapped at $1.41 to $212 million at 7.41% until June 15, 2012.
- U.S. $75 million at 6.25% swapped at $1.19 to $90 million at 5.65% until June 15, 2012.
- U.S. $50 million at 6.25% swapped at $1.17 to $59 million at 5.67% until June 15, 2012.
- U.S. $75 million at 6.25% swapped at $1.17 to $88 million at 5.61% until June 15, 2012.
At June 30, 2008, we had the following freestanding derivatives in place where Husky had entered into forward purchases of U.S. dollars to partially offset exposure on an embedded derivative (refer to Note 16 to the Consolidated Financial Statements):
- U.S. $119 million bought at $0.9854 for $117 million from January 2008 to June 2011.
- U.S. $119 million bought at $0.9772 for $116 million from January 2008 to June 2011.
- U.S. $119 million bought at $0.9670 for $115 million from January 2008 to June 2011.
At June 30, 2008 the cost of a U.S. dollar in Canadian currency was $1.0186.
Our results are affected by the exchange rate between the Canadian and U.S. dollar. The majority of our revenues are received in U.S. dollars or from the sale of oil and gas commodities that receive prices determined by reference to U.S. benchmark prices. The majority of our expenditures are in Canadian dollars. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the revenues received from the sale of oil and gas commodities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of oil and gas commodities.
In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky's U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At June 30, 2008, 90% or $1.9 billion of our long-term debt was denominated in U.S. dollars. The percentage of our long-term debt exposed to the Cdn/U.S. exchange rate decreases to 73% when cross currency swaps are considered.
Effective July 1, 2007, our U.S. $1.5 billion of debt financing related to the Lima acquisition was designated as a hedge of the net investment in the U.S. refining operations, which are considered self-sustaining. During the second quarter of 2008, we repaid our bridge financing of U.S. $750 million. As a result, the net investment hedge is limited to the remaining U.S. $750 million. As at June 30, 2008, unrealized foreign exchange losses arising from the translation of the debt were $40 million, net of tax of $7 million which was recorded in "Other Comprehensive Income."
8. Critical Accounting Estimates
Certain of our accounting policies require that we make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. For a discussion about those accounting policies, please refer to our Management's Discussion and Analysis for the year ended December 31, 2007 available at www.sedar.com.
9. Changes in Accounting Policies
Inventories
Effective January 1, 2008, we adopted the Canadian Institute of Chartered Accountants ("CICA") section 3031, "Inventories," which replaced CICA section 3030 of the same name. The new guidance provides additional measurement and disclosure requirements and requires the reversal of previous impairment write-downs when there is a change in the situation that caused the impairment. The transitional provisions of section 3031 provided entities with the option of applying this guidance retrospectively and restating prior periods in accordance with section 1506, "Accounting Changes" or adjusting opening retained earnings and not restating prior periods. The adoption of this standard did not have an impact on our financial statements.
Financial Instruments - Disclosure and Presentation
Effective January 1, 2008, we adopted CICA section 3862, "Financial Instruments - Disclosures" and CICA section 3863, "Financial Instruments - Presentation," which replaced CICA section 3861, "Financial Instruments - Disclosure and Presentation." Section 3862 outlines the disclosure requirements for financial instruments and non-financial derivatives. This guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, section 3862 requires disclosure of the significance of financial instruments on our financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments.
The presentation requirements under section 3863 are relatively unchanged from section 3861. Refer to Note 16 to the Consolidated Financial Statements for the additional disclosures under section 3862.
Capital Disclosures
Effective January 1, 2008, we adopted CICA section 1535, "Capital Disclosures." This new guidance requires disclosure about our objectives, policies and processes for managing capital. These disclosures include a description of what we manage as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into our management of capital, whether the requirements have been complied with, or consequence of non-compliance and an explanation of how we are meeting our objectives for managing capital. In addition, quantitative disclosures regarding capital are required. Refer to Note 17 to the Consolidated Financial Statements.
International Financial Reporting Standards
In January 2006, the Canadian Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of the AcSB's strategic plan, Canadian publicly accountable entities will be required to report under International Financial Reporting Standards ("IFRS"), which will replace Canadian generally accepted accounting principles ("GAAP") for years beginning on or after January 1, 2011. An omnibus exposure draft was issued by the AcSB in the second quarter of 2008, which incorporates IFRS into the CICA Handbook and prescribes the transitional provisions for adopting IFRS. Currently, we are assessing the effects of adoption and developing a plan accordingly. We will continue to monitor any changes in the adoption of IFRS and will update plans as necessary.
10. Outstanding Share Data
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July 15 December 31
(in thousands) 2008 2007
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Issued and outstanding
Number of common shares 849,143 848,960
Number of stock options 27,481 30,131
Number of stock options exercisable 7,456 4,494
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11. Reader Advisories
This MD&A should be read in conjunction with the Consolidated Financial Statements and related Notes. Readers are encouraged to refer to Husky's MD&A and Consolidated Financial Statements and 2007 Annual Information Form filed in 2008 with Canadian regulatory agencies and Form 40-F filed with the Securities and Exchange Commission, the U.S. regulatory agency. These documents are available at www.sedar.com, at www.sec.gov and at www.huskyenergy.com.
Use of Pronouns and Other Terms Denoting Husky
In this MD&A the pronouns "we," "our" and "us" and the terms "Husky" and "the Company" denote the corporate entity Husky Energy Inc. and its subsidiaries on a consolidated basis.
Standard Comparisons in this Document
Unless otherwise indicated, the discussions in this MD&A with respect to results for the three months ended June 30, 2008 are compared with results for the three months ended June 30, 2007 and results for the six months ended June 30, 2008 are compared with results for the six months ended June 30, 2007. Discussions with respect to Husky's financial position as at June 30, 2008 are compared with its financial position at December 31, 2007.
Additional Reader Guidance
- The Consolidated Financial Statements and comparative financial information included in this Interim Report have been prepared in accordance with Canadian GAAP.
- All dollar amounts are in millions of Canadian dollars, unless otherwise indicated.
- Unless otherwise indicated, all production volumes quoted are gross, which represent the Company's working interest share before royalties.
- Prices quoted include or exclude the effect of hedging as indicated.
Non-GAAP Measures
Disclosure of Cash Flow from Operations
Management's Discussion and Analysis contains the term "cash flow from operations," which should not be considered an alternative to, or more meaningful than "cash flow - operating activities" as determined in accordance with generally accepted accounting principles as an indicator of our financial performance. Cash flow from operations or earnings is presented in our financial reports to assist management and investors in analyzing operating performance by business in the stated period. 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:
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Three months Six months
ended June 30 ended June 30
(millions of dollars) 2008 2007 2008 2007
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Non-GAAP Cash flow from operations $ 2,090 $ 1,257 $ 3,631 $ 2,581
Settlement of asset
retirement obligations (7) (7) (24) (21)
Change in non-cash working
capital (29) (114) (326) (752)
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GAAP Cash flow - operating
activities $ 2,054 $ 1,136 $ 3,281 $ 1,808
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Disclosure of Operating Netback
Operating netback is a common non-GAAP metric used in the oil and gas industry. This measurement helps management and investors to evaluate the specific operating performance by product at the oil and gas lease level. It is equal to product revenue less transportation costs, royalties and lease operating costs divided by either a barrel of oil equivalent or an mcf of gas equivalent.
Cautionary Note Required by National Instrument 51-101
The Company uses the terms barrels of oil equivalent ("boe") and thousand cubic feet of gas equivalent ("mcfge"), which are calculated on an energy equivalence basis whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. Readers are cautioned that the terms boe and mcfge may be misleading, particularly if used in isolation. This measure is primarily applicable at the burner tip and does not represent value equivalence at the wellhead.
Husky's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Husky by Canadian securities regulatory authorities, which permits Husky to provide disclosure required by and consistent with the requirements of the United States Securities and Exchange Commission and the Financial Accounting Standards Board in the United States in place of much of the disclosure expected by National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities." Please refer to "Disclosure of Exemption Under National Instrument 51-101" on page 2 of our Annual Information Form for the year ended December 31, 2007 filed with securities regulatory authorities for further information.
Abbreviations
bbls barrels
bps basis points
mbbls thousand barrels
mbbls/day thousand barrels per day
mmbbls million barrels
mcf thousand cubic feet
mmcf million cubic feet
mmcf/day million cubic feet per day
bcf billion cubic feet
tcf trillion cubic feet
boe barrels of oil equivalent
mboe thousand barrels of oil equivalent
mboe/day thousand barrels of oil equivalent per day
mmboe million barrels of oil equivalent
mcfge thousand cubic feet of gas equivalent
GJ gigajoule
mmbtu million British Thermal Units
mmlt million long tons
NGL natural gas liquids
WTI West Texas Intermediate
NYMEX New York Mercantile Exchange
NIT NOVA Inventory Transfer
LIBOR London Interbank Offered Rate
CDOR Certificate of Deposit Offered Rate
SEDAR System for Electronic Document Analysis and Retrieval
FPSO Floating production, storage and offloading vessel
FEED Front-end engineering design
Terms
Bitumen A naturally occurring viscous mixture consisting
mainly of pentanes and heavier hydrocarbons. It is
more viscous than 10 degrees API
Capital Employed Short- and long-term debt and shareholders' equity
Capital Expenditures Includes capitalized administrative expenses and
capitalized interest but does not include proceeds
or other assets
Capital Program Capital expenditures not including capitalized
administrative expenses or capitalized interest
Cash Flow from Earnings from operations plus non-cash charges
Operations before settlement of asset retirement obligations
and change in non-cash working capital
Corporate Reinvestment Net capital expenditures (capital expenditures net
Ratio of proceeds from asset sales) plus corporate
acquisitions (net assets acquired) divided by cash
flow from operations
Dated Brent Prices which are dated less than 15 days prior to
loading for delivery
Debt to Capital Total debt divided by total debt and shareholders'
Employed equity
Delineation Well A well in close proximity to an oil or gas discovery
well that helps determine the areal extent of the
reservoir
Diluent A lighter gravity liquid hydrocarbon, usually
condensate or synthetic oil, added to heavy oil to
facilitate transmissibility through a pipeline
Embedded Derivative Implicit or explicit term(s) in a contract that
affects some or all of the cash flows or the value
of other exchanges required by the contract
Equity Shares, retained earnings and accumulated other
comprehensive income
Feedstock Raw materials which are processed into petroleum
products
Front-end Engineering Preliminary engineering and design planning, which
Design among other things, identifies project objectives,
scope, alternatives, specifications, risks, costs,
schedule and economics
Glory Hole An excavation in the seabed where the wellheads and
other equipment are situated to protect them from
scouring icebergs
Gross/Net Acres/Wells Gross refers to the total number of acres/wells in
which an interest is owned. Net refers to the sum of
the fractional working interests owned by a company
Gross Reserves/ A company's working interest share of
Production reserves/production before deduction of royalties
Hectare One hectare is equal to 2.47 acres
Near-month Prices Prices quoted for contracts for settlement during
the next month
NOVA Inventory Exchange or transfer of title of gas that has been
Transfer received into the NOVA pipeline system but not yet
delivered to a connecting pipeline
Return on Capital Net earnings plus after tax interest expense divided
Employed by average capital employed
Return on Shareholders' Net earnings divided by average shareholders' equity
Equity
Stratigraphic Well A geologically directed test well to obtain
information. These wells are usually drilled without
the intention of being completed for production
Synthetic Oil A mixture of hydrocarbons derived by upgrading heavy
crude oils, including bitumen, through a process
that reduces the carbon content and increases the
hydrogen content
Three Dimensional Seismic imaging which uses a grid of numerous cables
(3-D) Seismic rather than a few lines stretched in one line
Total Debt Long-term debt including current portion and bank
operating loans
Turnaround Scheduled performance of plant or facility
maintenance
12. Forward-Looking Statements and Information
Certain statements in this release and Interim Report are forward-looking statements and information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. We hereby provide cautionary statements identifying important factors that could cause our actual results to differ materially from those projected in these forward-looking statements. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "intend," "plan," "projection," "could," "vision," "goals," "objective," "target," "schedules" and "outlook") are not historical facts and are forward-looking and may involve estimates and assumptions and are subject to risks, uncertainties and other factors some of which are beyond our control and difficult to predict. Accordingly, these factors could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. Therefore, any such forward-looking statements are qualified in their entirety by reference to the factors discussed throughout this release.
In particular, forward-looking statements in this release and Interim Report include, but are not limited to: our 2008 revised production guidance and capital spending guidance, our development plans for the North Amethyst, West White Rose oil fields and South White Rose oil field extension, our plans to undertake a 3-D seismic acquisition program in the Jeanne d'Arc Basin and our plans to participate in an exploration well in the Flemish Pass Basin, our production optimization plans for the Tucker in-situ oil sands project, our Sunrise multiphase development plans, our development plans for the McMullen property, our Caribou and Saleski oil sands projects plans, our Northwest Territories exploration program, our exploration and delineation drilling plans for the South China Sea, the receipt of an extension of the PSC for the Madura BD natural gas and NGL field and regulatory approval for the East Bawean II exploration block two-well work program, our 2-D seismic acquisition programs and completion of an aero-gravity and magnetic survey for offshore Greenland, our plans to install various enhanced recovery schemes in Western Canada intended to increase reserves and our review options in respect of reconfiguring and expanding the Lima refinery and our plans to modify the Toledo refinery.
Although we believe that the expectations reflected by the forward-looking statements presented in this release and Interim Report are reasonable, our forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to us about ourselves and the businesses in which we operate. Information used in developing forward-looking statements has been acquired from various sources including third party consultants, suppliers, regulators and other sources. In some instances, material assumptions are disclosed elsewhere in this release and Interim Report in respect of forward-looking statements. We caution the reader that the following list of assumptions is not exhaustive. The material factors and assumptions used to develop the forward-looking statements include but are not limited to:
- no significant adverse changes to energy markets, competitive conditions, the supply and demand for crude oil, natural gas, NGL and refined petroleum products, or the political, economic and social stability of the jurisdictions in which we operate;
- no significant delays of the development, construction or commissioning of our projects that may result from the inability of suppliers to meet their commitments, lack of regulatory approvals or other governmental actions, harsh weather or other calamitous event;
- no significant disruption of our operations such as may result from harsh weather, natural disaster, accident, civil unrest or other calamitous event;
- no significant unexpected technological or commercial difficulties that adversely affect our exploration, development, production, processing or transportation;
- continuing availability of economical capital resources; demand for our products and our cost of operations;
- no significant adverse legislative and regulatory changes, in particular changes to the legislation and regulation governing fiscal regimes and environmental issues; environmental risks and liability under provincial/state, federal or other jurisdictions;
- stability of general domestic and global economic, market and business conditions; and
- no significant increase in the cost of our major growth projects.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include, but are not limited to:
- the prices we receive for our crude and natural gas production;
- demand for our products and our cost of operations;
- our ability to replace our proved oil and gas reserves in a cost-effective manner;
- the effect of weather and other environmental conditions;
- inability to obtain regulatory approvals to operate existing properties or develop significant growth projects;
- competitive actions of other companies, including increased competition from other oil and gas companies;
- business interruptions because of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us and that may or may not be financially recoverable;
- fluctuations in interest rates and foreign currency exchange rates;
- actions by governmental authorities, including changes in environmental and other regulations that may impose operating costs or restrictions in areas where we operate; and
- the inability to reach our estimated production levels from existing and future oil and gas development projects as a result of technological, commercial difficulties or other risk factor.
These risks, uncertainties and other factors are discussed in our Annual Information Form and our Form 40-F, available at www.sedar.com and www.sec.gov, respectively.
Further, any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by applicable law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
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June 30 December 31
(millions of dollars, except share data) 2008 2007
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(unaudited)
Assets
Current assets
Cash and cash equivalents $ 536 $ 208
Accounts receivable 2,171 1,622
Inventories 1,889 1,190
Prepaid expenses 66 28
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4,662 3,048
Property, plant and equipment (note 6) 31,062 29,407
Less accumulated depletion, depreciation and
amortization 12,460 11,602
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18,602 17,805
Goodwill (note 8) 675 660
Contribution receivable (note 6) 1,183 -
Other assets 174 184
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$ 25,296 $ 21,697
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Liabilities and Shareholders' Equity
Current liabilities
Accounts payable and accrued liabilities $ 2,945 $ 2,358
Long-term debt due within one year (note 10) 229 741
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3,174 3,099
Long-term debt (note 10) 1,900 2,073
Contribution payable (note 6) 1,339 -
Other long-term liabilities (note 11) 959 918
Future income taxes 4,616 3,957
Shareholders' equity
Common shares (note 13) 3,559 3,551
Retained earnings 9,806 8,176
Accumulated other comprehensive income (57) (77)
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