Husky Energy Reports 2008 Third Quarter Results
Husky Energy Inc. (TSX: HSE) reported net earnings of $1.27 billion or $1.50 per share (diluted) in the third quarter of 2008, an increase of 65 percent from $769 million or $0.91 per share (diluted) in the same quarter of 2007. Cash flow from operations in the third quarter of 2008 was $2.0 billion or $2.36 per share (diluted), a 41 percent increase compared with $1.4 billion or $1.67 per share (diluted) in the same quarter of 2007. Sales and operating revenues, net of royalties, were $7.7 billion in the third quarter of 2008, an increase of 77 percent compared with $4.4 billion in the same quarter of 2007.
“Husky’s strong earnings and cash flow allow the Company to finance its current capital program, redeem debt and accumulate cash, positioning the Company for further investment opportunities,” said John C.S. Lau, President & Chief Executive Officer of Husky Energy Inc. “Husky’s focus on financial discipline in respect of costs and project execution over the years has positioned the Company to perform well in these volatile financial and commodity markets.”
In the third quarter of 2008, total production averaged 355,900 barrels of oil equivalent per day, compared with 369,900 barrels of oil equivalent per day in the third quarter of 2007, a reduction of four percent. Total crude oil and natural gas liquids production was 256,200 barrels per day, compared with 266,500 barrels per day in 2007. Natural gas production was 598 million cubic feet per day, compared with 620 million cubic feet per day in the same period of 2007. The decrease in production of barrels of oil equivalent is generally in line with Husky’s updated guidance as reported in the second quarter of 2008.
For the first nine months of 2008, Husky’s net earnings were $3.5 billion or $4.15 per share (diluted), compared with $2.1 billion or $2.52 per share (diluted) in the first nine months of 2007. Cash flow from operations was $5.6 billion or $6.63 per share (diluted) in the first nine months of 2008, compared with $4.0 billion or $4.71 per share (diluted) in the same period of 2007. Sales and operating revenues, net of royalties, were $20.0 billion in the first nine months of 2008, compared with $10.8 billion in the first nine months of 2007.
Production for the first nine months of 2008 was 355,100 barrels of oil equivalent per day, compared with 379,600 barrels of oil equivalent per day in the same period in 2007. Crude oil and natural gas liquids production was 254,700 barrels per day, compared with 275,400 barrels per day in the first nine months of 2007. This reflects the severe ice pack and iceberg winter conditions off the East Coast of Canada and the previously disclosed delay in ramp up of production at the Tucker Oil Sands Project. Natural gas production was 602 million cubic feet per day as compared with 625 million cubic feet per day during the same period of 2007.
In the third quarter, Husky signed a joint venture agreement acquiring a 50 percent working interest in 844,000 net acres of leasehold ownership and wells in the Columbia River Basin in the states of Washington and Oregon, for a consideration of approximately U.S. $100 per acre for 422,000 acres.
During the third quarter, work progressed at the Sunrise Oil Sands Project on area infrastructure and site preparation. Phase one production is expected to commence approximately four years following project sanction.
In the White Rose satellite developments off Canada’s East Coast, engineering work has progressed well and drilling of stratigraphic wells commenced during the third quarter. In September, the eighth producing well in the White Rose field commenced production. Husky has also been successful in acquiring two exploration blocks on the Labrador Shelf off the coast of Labrador.
Offshore China, Husky’s contracted deep water drilling rig West Hercules continued with commissioning and acceptance testing in Korea. Delivery of the rig is expected at the end of October 2008 and we expect to commence appraisal drilling at the Liwan field in November. Husky initially plans to drill four delineation wells on the Liwan discovery and two exploration wells on satellite prospects in the area. Additionally, two shallow water rigs are currently being contracted to drill a total of four exploration wells in the South China Sea, East China Sea and Yingge Hai basin. Husky expects to commence drilling the first well in December 2008.
In Indonesia, the Madura BD field development plan was approved in July 2008 and Husky expects approval of the Madura Production Sharing Contract (PSC) extension from the regulatory authorities prior to year-end. On the East Bawean II PSC, Husky has secured a jack up drilling rig to drill two exploration wells in 2009. Husky has been awarded a PSC from the government of Indonesia for a 100 percent interest in the North Sambawa II Block in the East Java Sea.
In the downstream business, refining crack spread margins during the start of the quarter were low with pressure on gasoline cracks partially offset by firmer distillate spreads. Crude supply disruptions associated with hurricanes Gustav, Hanna and Ike widened spreads later in the quarter but impacted crude oil feedstock availability. These two factors resulted in slightly lower refinery throughput than the same period in 2007. The Lima Refinery had a high on-stream reliability during the quarter. The Toledo Refinery was limited in its ability to capitalize on wider sweet/sour differentials as production was also impacted by turnaround activities. Husky has completed the conceptual stage of reconfiguring the Lima Refinery to process heavier feedstocks.
Husky’s earnings are largely determined by realized prices for crude oil and natural gas, including the effects of changes to the U.S./Canadian exchange rate. Recently, changes in the crude oil and natural gas pricing and the exchange rate have moved together, with changes in the exchange rate providing partial offset to changes in crude oil and natural gas pricing. As at October 20, 2008 crude oil (WTI) and natural gas (NYMEX) prices had fallen to U.S. $74.25 per barrel (26 percent) and U.S. $6.74 per million British Thermal Units (nine percent) respectively from September 30, 2008, partially offset by a 12 percent reduction in the exchange rate to $0.835 U.S. dollar per Canadian dollar at the same date.
Husky continues to strengthen its financial position and has a very strong balance sheet. Total long-term debt including current portion at September 30, 2008 was $1,719 million compared with $2,814 million at December 31, 2007. The total debt was substantially offset by cash and cash equivalents of $966 million resulting in net debt of $753 million at September 30, 2008. Debt to cash flow from operations decreased to 0.2 times at the end of the third quarter compared with 0.5 times at the 2007 year-end. The ratio of debt to capital employed improved to 11 percent at September 30, 2008 from 19 percent at December 31, 2007.
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”) OCTOBER 21, 2008 —————————————————————————- Table of Contents 1. Summary of Quarterly Financial 7. Risk Management Results 2. Business Environment 8. Critical Accounting Estimates 3. Results of Operations 9. Accounting Policies 4. Liquidity and Capital Resources 10. Outstanding Share Data 5. Capability to Deliver Results and 11. Reader Advisories the Strategic Plan 6. Key Growth Highlights 12. Forward-Looking Statements and Information —————————————————————————- 1. Summary of Quarterly Financial Results The following table shows our net earnings by industry sector and includes corporate expenses and intersegment profit eliminations. —————————————————————————- Three months ended Sept. 30 June 30 March 31 Dec. 31 (millions of dollars, except per share amounts and ratios) 2008 2008 2008 2007 —————————————————————————- Sales and operating revenues, net of royalties $ 7,715 $ 7,199 $ 5,086 $ 4,760 Net earnings by sector Upstream $ 1,079 $ 1,239 $ 717 $ 864 Midstream 100 153 144 218 Downstream (9) 194 38 103 Corporate and eliminations 102 (223) (12) (111) —————————————————————————- Net earnings $ 1,272 $ 1,363 $ 887 $ 1,074 —————————————————————————- —————————————————————————- Per share – Basic and diluted $ 1.50 $ 1.61 $ 1.04 $ 1.26 Cash flow from operations 2,000 2,090 1,541 1,425 Per share – Basic and diluted 2.36 2.46 1.82 1.68 Ordinary quarterly dividend per common share 0.50 0.40 0.33 0.33 Special dividend per common share – – – – Total assets 26,292 25,296 24,391 21,697 Cash and cash equivalents 966 536 366 208 Total long-term debt including current portion 1,719 2,129 3,019 2,814 Return on equity (1) (percent) 36.6 34.9 31.2 30.2 Return on average capital employed (1) (percent) 31.6 30.9 26.5 25.7—————————————————————————- —————————————————————————- Three months ended Sept. 30 June 30 March 31 Dec. 31 (millions of dollars, except per share amounts and ratios) 2007 2007 2007 2006 —————————————————————————- Sales and operating revenues, net of royalties $ 4,351 $ 3,163 $ 3,244 $ 3,084 Net earnings by sector Upstream $ 516 $ 636 $ 580 $ 453 Midstream 129 77 111 105 Downstream 121 53 20 10 Corporate and eliminations 3 (45) (61) (26) —————————————————————————- Net earnings $ 769 $ 721 $ 650 $ 542 —————————————————————————- —————————————————————————- Per share – Basic and diluted $ 0.91 $ 0.85 $ 0.77 $ 0.64 Cash flow from operations 1,420 1,257 1,324 1,207 Per share – Basic and diluted 1.67 1.48 1.56 1.42 Ordinary quarterly dividend per common share 0.25 0.25 0.25 0.25 Special dividend per common share – – 0.25 – Total assets 20,718 17,969 17,781 17,933 Cash and cash equivalents 7 133 – 442 Total long-term debt including current portion 2,835 1,423 1,527 1,611 Return on equity (1) (percent) 26.6 27.1 32.1 31.8 Return on average capital employed (1) (percent) 22.3 23.8 27.3 27.0 —————————————————————————- —————————————————————————- (1) Calculated for the 12 months ended for the dates shown.
– Financial position remains strong, financing capital programs and retiring debt with cash generated from operating activities
– Production consistent with second quarter guidance
– Average commodity price environment remained strong during the quarter
– Refined product margins were low compared with the same period in the previous year due to weak demand for products combined with supply disruptions in both Canada and the U.S.A.
– Marketing margins in the third quarter of 2008 were impacted by declines in commodity prices at the end of the quarter resulting in lower broker profits
2. Business Environment —————————————————————————- Average Benchmarks Three months ended Sept. June March Dec. Sept. June 30 30 31 31 30 30 2008 2008 2008 2007 2007 2007 —————————————————————————- WTI crude oil (1) (U.S. $/bbl) 117.98 123.98 97.90 90.68 75.38 65.03 Brent crude oil (2) (U.S. $/bbl) 114.78 121.38 96.90 88.70 74.87 68.76 Canadian light crude 0.3% sulphur ($/bbl) 122.53 126.73 98.20 87.19 80.70 72.61 Lloyd heavy crude oil @ Lloydminster ($/bbl) 96.17 89.70 64.23 42.03 43.61 39.02 NYMEX natural gas (1) (U.S. $/mmbtu) 10.24 10.93 8.03 6.97 6.16 7.55 NIT natural gas ($/GJ) 8.76 8.86 6.76 5.69 5.31 6.99 WTI/Lloyd crude blend differential (U.S. $/bbl) 18.34 21.95 21.81 34.06 23.50 20.36 New York Harbor 3:2:1 crack spread (U.S. $/bbl) 10.96 14.50 10.09 8.23 11.91 24.18 U.S./Canadian dollar exchange rate (U.S. $) 0.960 0.990 0.996 1.018 0.957 0.911 —————————————————————————- —————————————————————————- (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.
Oil and Gas Prices
Our earnings are largely determined by realized prices for crude oil and natural gas including the effects of changes in the U.S./Canadian dollar exchange rate. During the third quarter of 2008 our upstream industry segment contributed 85% to consolidated net earnings. Significant fluctuations in our earnings are related to the volatility of oil and gas prices which are determined by market forces over which we have no control.
During the first nine months of 2008, the near-month price of WTI averaged U.S. $113.52/bbl and peaked above U.S. $145 in mid July before declining to U.S. $91.15/bbl during September. The average for the third quarter was U.S. $117.98/bbl and the price at the end of September was U.S. $100.64/bbl and by October 20th was U.S. $74.25/bbl.
During the third quarter of 2008 the light/heavy crude oil differential averaged 16% of WTI compared with 31% of WTI in the third quarter of 2007. Higher demand for heavy crude was in response to lower crack spreads and increased demand for distillates.
Natural gas prices quoted on the NYMEX rose sharply through the first half of 2008 and were, on average, 37% higher than the same period in 2007 based on lower storage levels and higher demand. During the third quarter of 2008, natural gas prices plummetted as natural gas storage levels increased, surpassing five-year average levels by mid August. At the end of the third quarter of 2008, natural gas inventory in underground storage in the United States was 2% higher than the five year average and 4% lower than the same date in 2007. The NYMEX near-month price ended the third quarter of 2008 at U.S. $7.44/mmbtu and by October 20th was U.S. $6.74/mmbtu.
Foreign Exchange
The majority of our revenues are denominated in U.S. dollars. A weakening of the Canadian dollar against the U.S. dollar positively impacts our revenue stream, offsetting the impact of lower oil and natural gas prices.
During the third quarter the Canadian dollar weakened 3.9% against the U.S. dollar, closing at $0.944 U.S. per Canadian dollar at September 30, 2008 and by October 20th had further weakened to $0.835 U.S. per Canadian dollar. The average exchange rate for the quarter was $0.96 U.S. per Canadian dollar compared to $0.99 U.S. per Canadian dollar in the second quarter of 2008.
Refinery Crack Spreads
The 3:2:1 crack spread is the key indicator for refining margins as 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 third quarter of 2008, the U.S. New York Harbor crack spread averaged U.S. $10.96/bbl compared with U.S. $11.91/bbl in the third quarter of 2007 due to lower demand for motor fuel, particularly gasoline, partially offset in September by hurricane related refinery outages.
Actual crack spreads achieved are also impacted by the timing of delivery of crude oil purchases, accounted for on a FIFO basis which is consistent with Canadian GAAP.
Cost Environment
The oil and gas industry is experiencing an increase in costs in excess of the general rate of inflation. These increases affect the cost of operating our oil and gas properties, processing plants and refineries. They also affect our capital projects which are susceptible to cost volatility.
Global Financial Crisis
The current global financial crisis has reduced liquidity in financial markets, restricted access to financing and caused significant volatility in commodity prices. These will impact the performance of the economy going forward. However, companies with strong cash generation from operations, availability of cash and cash equivalents, low debt with long maturities and unused committed credit facilities will be better positioned to manage through this crisis.
Sensitivity Analysis
The following table indicates the relative annual effect of changes in certain key variables on our pre-tax cash flow and net earnings. The analysis is based on business conditions and production volumes during the third quarter of 2008. Each item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.
2008 Third Effect on Sensitivity Quarter Annual Pre-tax Effect on Annual Analysis Average Increase Cash Flow (7) Net Earnings (7) —————————————————————————- ($/share) ($/share) ($ millions) (8) ($ millions) (8) Upstream and Midstream WTI benchmark crude oil price $117.98 U.S. $1.00/bbl 75 0.09 53 0.06 NYMEX benchmark natural gas price (1) $ 10.24 U.S. $0.20/mmbtu 25 0.03 18 0.02 WTI/Lloyd crude blend differential (2) $ 18.34 U.S. $1.00/bbl (9) (0.01) (7) (0.01)Downstream Light oil margins $ 0.027 Cdn $0.005/litre 15 0.02 10 0.01 Asphalt margins $ 10.33 Cdn $1.00/bbl 13 0.01 8 0.01 New York Harbor 3:2:1 crack spread (3) $ 10.96 U.S. $1.00/bbl 67 0.08 42 0.05 Consolidated Exchange rate (U.S. $ per Cdn $) (4) $ 0.960 U.S. $0.01 (98) (0.12) (70) (0.08) Interest rate (5) 100 basis points – – – – Period end translation of U.S. $ debt (U.S. $ per Cdn $) $ 0.944 (6) U.S. $0.01 – – 12 0.01 —————————————————————————- —————————————————————————- (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, including cash balances. (5) An interest rate change would not have an impact as Husky did not have variable rate debt outstanding as of September 30, 2008. (6) U.S./Canadian dollar exchange rate at September 30, 2008. (7) Excludes derivatives. (8) Based on 849.3 million common shares outstanding as of September 30, 2008. 3. Results of Operations 3.1 Upstream —————————————————————————- Upstream Net Earnings Summary Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars) 2008 2007 2008 2007 —————————————————————————- Gross revenues $ 3,032 $ 1,803 $ 8,366 $ 5,394 Royalties 691 307 1,772 740 —————————————————————————- Net revenues 2,341 1,496 6,594 4,654 Operating and administration expenses 407 371 1,200 1,038 Depletion, depreciation and amortization 369 413 1,111 1,219 Other 24 (39) (28) (88) Income taxes 462 235 1,276 753 —————————————————————————- Net earnings $ 1,079 $ 516 $ 3,035 $ 1,732 —————————————————————————- —————————————————————————-
Third Quarter
During the third quarter of 2008, upstream net revenues increased by $845 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower sales volumes and higher royalties.
During the third quarter of 2008, our realized heavy crude oil and bitumen prices averaged 83% of our realized light crude oil and NGL prices versus 57% during the same period in 2007.
Nine Months
For the nine months ended September 30, 2008, upstream net revenues increased by $1,940 million compared with the same period in 2007. Higher crude oil, natural gas and sulphur prices more than offset lower volumes and higher royalties.
During the first nine months of 2008, our realized heavy crude oil and bitumen prices averaged 75% of our realized light crude oil and NGL prices versus 57% during the same period in 2007.
Upstream Net Earnings Variance Analysis Pricing —————————————————————————- Average Sales Prices Realized Three months Nine months ended Sept. 30 ended Sept. 30 2008 2007 2008 2007 —————————————————————————- Crude Oil ($/bbl) Light crude oil & NGL $ 114.85 $ 76.00 $ 110.72 $ 70.49 Medium crude oil 103.60 54.55 93.32 49.69 Heavy crude oil & bitumen 95.55 43.64 83.13 39.84 Total average 105.57 60.91 97.42 56.59 Natural Gas ($/mcf) Average 8.66 5.18 8.30 6.34 —————————————————————————- —————————————————————————- Oil and Gas Production —————————————————————————- Three months Nine months Daily Gross Production ended Sept. 30 ended Sept. 30 2008 2007 2008 2007 —————————————————————————- Crude oil & NGL (mbbls/day) Western Canada Light crude oil & NGL 24.4 25.1 24.6 26.8 Medium crude oil 26.9 26.7 26.9 27.1 Heavy crude oil & bitumen 107.6 106.5 105.8 106.6 —————————————————————————- 158.9 158.3 157.3 160.5 East Coast Canada White Rose – light crude oil 72.7 79.2 71.9 86.3 Terra Nova – light crude oil 12.6 16.3 13.4 15.4 China Wenchang – light crude oil & NGL 12.0 12.7 12.1 13.2 —————————————————————————- Total crude oil & NGL 256.2 266.5 254.7 275.4 —————————————————————————- Natural gas (mmcf/day) 598.3 620.1 602.2 625.2 —————————————————————————- Total (mboe/day) 355.9 369.9 355.1 379.6 —————————————————————————- —————————————————————————-
Crude Oil and NGL Production
Third Quarter
In the third quarter of 2008, crude oil and NGL production decreased by 4% compared with the same period in 2007. On the East Coast, light oil production was lower due to the delayed start up of the eighth producing well at White Rose, which was a result of ice conditions in the second quarter, and a 4-day shut down due to offloading operational restrictions combined with tanker availability. At Terra Nova operational and maintenance issues also resulted in reduced production. White Rose was shut down for 16 days for scheduled maintenance in the third quarter of 2007.
Nine Months
In the first nine months of 2008, crude oil and NGL production decreased by 8% compared with the same period of the previous year. Production from the White Rose field was shut down for 11 days in April due to the encroachment of severe ice pack and iceberg conditions. In June 2008, Terra Nova was shut down for 14 days for a scheduled maintenance turnaround compared to near capacity production in the nine month period in 2007.
During the first nine months of 2008, crude oil and NGL production from Western Canada was down 2% compared with the first nine months of 2007 primarily due to high reservoir decline, development delays and shut-in facilities.
Natural Gas Production
Third Quarter
Production of natural gas decreased by 4% compared with the same period of the previous year. In 2007 a strategic decision was made to reduce drilling for natural gas in response to low natural gas prices and pending higher Alberta gas royalties. Higher reservoir declines were also a factor.
In the third quarter of 2008, 59% 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.
Nine Months
In addition to the factors affecting the third quarter, natural gas production was 4% lower in the first nine months of the year compared with the same period in 2007 due to severe cold weather in Western Canada in the first quarter of 2008.
Production Guidance —————————————————————————- 2008 Gross Production Guidance Nine months ended Year ended Guidance Sept. 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 – 124 106 107 —————————————————————————- 281 – 301 255 273 Natural gas (mmcf/day) 625 – 655 602 623 Total barrels of oil equivalent (mboe/day) 385 – 410 355 377 —————————————————————————- —————————————————————————-
Production for 2008 is expected to be 358 to 366 mbbls per day, five to seven percent below our guidance range. Royalties
In the third quarter of 2008, royalty rates in Western Canada averaged 19% as a percentage of gross revenue, up from 15% in the third quarter of 2007.
In March 2008, the Tier II incremental royalty rate became effective for White Rose. As a result, East Coast offshore royalty rates averaged 31% as a percentage of gross revenue in the third quarter compared with 21% in the third quarter of 2007.
Royalty rates for the first nine months of 2008 averaged 17% in Western Canada and 29% offshore the East Coast compared with 15% and 11% respectively in 2007.
Unit Operating Costs
Third Quarter
In the third quarter of 2008, operating costs in Western Canada averaged $13.58/boe compared with $11.47/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 complex 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 the 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 were $8 million lower in the third quarter of 2008 compared with the third quarter of 2007 and averaged $4.93/bbl compared with $5.34/bbl. In 2007 White Rose was shut down for 16 days for scheduled maintenance. Operating costs at the South China Sea offshore operations averaged $3.77/bbl in the third quarter of 2008 compared with $3.18/bbl in the same period in 2007, as a result of higher maintenance costs for the maturing field.
Nine Months
Total upstream unit operating costs in the first nine months of 2008 averaged $10.96/boe compared with $8.93/boe in the same period in 2007. In addition to the factors affecting the third 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. In the second quarter operating costs increased compared with the previous year due to additional resources required to manage ice encroachment and subsurface mechanical issues on the East Coast.
Unit Depletion, Depreciation and Amortization
Third Quarter
Total unit DD&A averaged $11.27/boe in the third quarter of 2008 compared with $12.14/boe in the third quarter of 2007. In Canada, unit DD&A was $11.27/boe, a decrease of 4% from the third 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 $1.6 billion or $1.72/boe in the third quarter of 2008. The Sunrise oil sands project currently does not have any proved reserves attributed to it.
Nine Months
For the first nine months of 2008, total unit DD&A averaged $11.43/boe compared with $11.76/boe during the same period in 2007. This was primarily due to the effect of the Sunrise disposition partially offset by a higher full cost base during the first nine months of 2008 compared with the first nine months of 2007.
———————————————————————– —– Netback Analysis Three months Nine months ended Sept. 30 ended Sept. 30 2008 2007 2008 2007 —————————————————————————- $ $ $ $ Total Crude oil equivalent (per boe) (1) Gross price 90.54 52.30 83.95 51.50 Royalties 20.35 9.02 17.81 7.13 —————————————————————————- Net sales price 70.19 43.28 66.14 44.37 Operating costs (2) 11.20 9.60 10.96 8.93 —————————————————————————- Operating netback 58.99 33.68 55.18 35.44 DD&A 11.27 12.14 11.43 11.76 Administration expenses and other (2) 0.71 (0.55) 0.24 (0.30) —————————————————————————- Earnings before income taxes 47.01 22.09 43.51 23.98 —————————————————————————- —————————————————————————- Western Canada Crude oil (per boe) (1) Light crude oil Gross price 98.38 62.29 92.02 59.41 Royalties 14.19 7.39 12.68 6.61 —————————————————————————- Net sales price 84.19 54.90 79.34 52.80 Operating costs (2) 8.75 12.39 13.11 12.68 —————————————————————————- Operating netback 75.44 42.51 66.23 40.12 —————————————————————————- Medium crude oil Gross price 100.95 53.38 90.92 49.12 Royalties 17.91 9.45 16.29 8.60 —————————————————————————- Net sales price 83.04 43.93 74.63 40.52 Operating costs (2) 15.72 15.12 15.48 13.73 —————————————————————————- Operating netback 67.32 28.81 59.15 26.79 —————————————————————————- Heavy crude oil & bitumen Gross price 94.88 43.43 82.57 39.82 Royalties 16.25 5.52 12.27 5.07 —————————————————————————- Net sales price 78.63 37.91 70.30 34.75 Operating costs (2) 16.41 12.80 15.77 12.53 —————————————————————————- Operating netback 62.22 25.11 54.53 22.22 —————————————————————————- Natural gas (per mcfge) (3) Gross price 8.99 5.48 8.66 6.51 Royalties 1.84 0.95 1.71 1.26 —————————————————————————- Net sales price 7.15 4.53 6.95 5.25 Operating costs (2) 1.82 1.48 1.60 1.39 —————————————————————————- Operating netback 5.33 3.05 5.35 3.86 —————————————————————————- East Coast Light crude oil (per boe) (1) Gross price 117.65 76.97 113.72 72.32 Royalties (4) 35.97 16.07 33.08 7.89 —————————————————————————- Net sales price 81.68 60.90 80.64 64.43 Operating costs (2) 4.93 5.34 5.22 4.12 —————————————————————————- Operating netback 76.75 55.56 75.42 60.31 —————————————————————————- International Light crude oil (per boe) (1) Gross price 114.80 77.48 115.19 73.54 Royalties 39.42 14.24 34.22 12.97 —————————————————————————- Net sales price 75.38 63.24 80.97 60.57 Operating costs (2) 4.12 3.18 4.64 3.72 —————————————————————————- Operating netback 71.26 60.06 76.33 56.85 —————————————————————————- —————————————————————————- (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 third quarter of 2008, a $24 million loss was recorded on an embedded derivative related to a drilling rig contract requiring payment in U.S. currency. This compares with a $39 million gain in the third quarter of 2007. A loss of $41 million was recorded in the first nine months of 2008 compared with a gain of $88 million for the same period in 2007. The payments required under this contract are expected to occur over the three-year period from late 2008. The amount will fluctuate with the U.S./Canadian forward exchange rate until actual contract settlement. Contracts to purchase U.S. currency had been entered into to offset approximately 60% of this derivative. During the third quarter of 2008, the Company unwound one of the contracts realizing a gain of $12 million. At September 30, 2008, the remaining contracts offset approximately 40% of the 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
At September 30, 2008, our overall upstream capital expenditures were 78% of the 2008 capital expenditure guidance. Our major upstream projects remain essentially on schedule and their ultimate completion dates are expected to be maintained.
———————————————————————– —– Capital Expenditures Summary (1) Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars) 2008 2007 2008 2007 —————————————————————————- Exploration Western Canada $ 167 $ 97 $ 476 $ 338 East Coast Canada and Frontier 49 28 94 33 Northwest United States 50 – 50 – International 53 21 115 46 —————————————————————————- 319 146 735 417 —————————————————————————- Development Western Canada 407 354 1,270 1,099 East Coast Canada 257 45 398 161 International – – 3 5 —————————————————————————- 664 399 1,671 1,265 —————————————————————————- $ 983 $ 545 $ 2,406 $ 1,682 —————————————————————————- —————————————————————————- (1) Excludes capitalized costs related to asset retirement obligations incurred during the period.
During the first nine months of 2008, capital expenditures were $1,746 million (73%) in Western Canada, $492 million (20%) off the East Coast of Canada, $50 million (2%) in the Northwest United States and $118 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. Ninety-one percent of the net exploration wells and 96% of the net development wells we drilled in the third quarter of 2008 resulted in wells capable of commercial production as compared with 95% and 97% respectively in the third quarter of 2007.
———————————————————————– —– Western Canada and Oil Sands Wells Drilled Three months Nine months ended Sept. 30 ended Sept. 30 2008 2007 2008 2007 Gross Net Gross Net Gross Net Gross Net —————————————————————————- Exploration Oil 10 10 23 23 38 36 56 56 Gas 17 11 16 13 81 64 85 72 Dry 3 2 3 2 23 21 13 12 —————————————————————————- 30 23 42 38 142 121 154 140 —————————————————————————- Development Oil 262 211 221 203 455 388 417 387 Gas 157 88 67 54 292 192 241 195 Dry 13 13 7 7 16 16 19 19 —————————————————————————- 432 312 295 264 763 596 677 601 —————————————————————————- Total 462 335 337 302 905 717 831 741 —————————————————————————- —————————————————————————-
Western Canada – Excluding Oil Sands
During the first nine months of 2008, we invested $1,489 million on exploration and development throughout the Western Canada Sedimentary Basin excluding oil sands. Of this, $386 million was invested on oil development and $246 million was invested on natural gas development. We drilled 709 net wells in the basin during the first nine months of 2008, resulting in 416 net oil wells and 256 net natural gas wells. In addition, $128 million was spent on production optimization and operating cost reduction initiatives. Capital spending on facilities, land acquisition and retention and environmental protection amounted to $168 million. During the first nine months of 2008, $294 million was spent to acquire producing properties.
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 nine months of 2008, we invested $241 million on drilling in these natural gas prone areas. During this period we drilled 26 net exploration wells in the foothills and deep basin regions; 19 were cased as natural gas wells. The remaining 95 net exploration wells were drilled primarily in the shallow regions of the Western Canada Sedimentary Basin.
Oil Sands
Oil sands capital expenditures totalled $257 million during the first nine months of 2008. At Tucker, we spent $107 million on drilling new well pairs, facility modification and new pad preparation. At Sunrise, we spent $108 million on engineering design, site preparation and facilities and equipment requisitions. At Caribou and Saleski we spent $42 million on project development.
East Coast Development
During the first nine months of 2008, we spent $398 million primarily for the North Amethyst and West White Rose tie-back development projects and the completion of an infill production well and other capital enhancements at White Rose. Construction commenced on North Amethyst and long lead equipment was procured. 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 nine months of 2008, we spent $94 million on two exploration wells in the Central Mackenzie Valley and on our East Coast seismic program.
Northwest United States
On September 30, 2008, we invested $50 million to acquire petroleum and natural gas rights in the Columbia River Basin located in southeastern Washington and northeast Oregon and a 50% interest in an exploration well currently being drilled.
International
During the first nine months of 2008, we spent $115 million on exploration drilling in the South China Sea and seismic data acquisition 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) (2) (millions of dollars) —————————————————————————- Western Canada – oil & gas $ 1,670 – oil sands 300 East Coast Canada 650 International 430 —————————————————————————- Total Upstream Capital Expenditures $ 3,050 —————————————————————————- —————————————————————————- (1) Excludes capitalized administrative costs and capitalized interest. (2) Upstream capital expenditures for the nine months ended September 30 were $2,406 million. 3.2 Midstream —————————————————————————- Upgrading Net Earnings Summary Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars, except where indicated) 2008 2007 2008 2007 —————————————————————————- Gross margin $ 163 $ 155 $ 502 $ 382 Operating and administration expenses 65 55 195 160 Other recoveries – (1) (2) (3) Depreciation and amortization 9 7 22 17 Income taxes 27 29 86 63 —————————————————————————- Net earnings $ 62 $ 65 $ 201 $ 145 —————————————————————————- —————————————————————————- Selected operating data: Upgrader throughput (1) (mbbls/day) 79.3 67.4 66.8 57.5 Synthetic crude oil sales (mbbls/day) 69.1 55.1 58.8 48.6 Upgrading differential ($/bbl) $ 26.09 $ 30.41 $ 27.94 $ 27.94 Unit margin ($/bbl) $ 25.60 $ 30.63 $ 31.10 $ 28.78 Unit operating cost (2) ($/bbl) $ 8.93 $ 8.93 $ 10.62 $ 10.21—————————————————————————- —————————————————————————- (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 heavy crude feedstock and the sales price of synthetic crude oil.
Upgrading Net Earnings Variance Analysis
Third Quarter
During the third quarter of 2008, the upgrading differential averaged $26.09/bbl, a decrease of $4.32 compared with the same period in 2007. The differential is equal to Husky Synthetic Blend, which sells at a premium to West Texas Intermediate, less Lloyd Heavy Blend. During the third quarter of 2008, the overall unit margin was 16% lower than the previous year due to the lower upgrading differential, partially offset by the addition of higher value low sulphur off-road diesel to the upgrader’s product stream and higher sulphur prices.
Upgrader throughput was 18% higher in the third quarter of 2008 compared with the same period in 2007. In 2007, the upgrader was operating one hydrocracker train at lower rates due to maintenance requirements. Unit operating costs were unchanged in the third quarter of 2008 compared with 2007.
Nine Months
During the first nine months of 2008, upgrading earnings were 39% higher than the year earlier. In addition to the factors affecting the third quarter, upgrader throughput was 16% higher in the nine-month period of 2008 compared with the same period in 2007. In 2007, throughput was lower due to a 49-day scheduled turnaround and installation of new coke drums during the second quarter. Throughput was below capacity during 2008 due to a temporary shutdown to replace the hydrogen plant catalyst during the second quarter.
———————————————————————– —– Infrastructure and Marketing Net Earnings Summary Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars, except where indicated) 2008 2007 2008 2007 —————————————————————————- Gross margin – pipeline $ 32 $ 33 $ 101 $ 87 – other infrastructure and marketing 34 71 213 191 —————————————————————————- 66 104 314 278 Operating and administration expenses 3 3 10 7 Depreciation and amortization 8 7 23 21 Income taxes 17 30 85 78 —————————————————————————- Net earnings $ 38 $ 64 $ 196 $ 172 —————————————————————————- —————————————————————————- Selected operating data: Aggregate pipeline throughput (mbbls/day) 494 506 512 502 —————————————————————————- —————————————————————————-
Third Quarter
Infrastructure and marketing net earnings in the third quarter of 2008 were $38 million compared with $64 million in the third quarter of 2007. Lower earnings were primarily due to lower brokering margins on crude oil and natural gas, as commodity prices decreased through the latter part of the third quarter of 2008, and declining gas storage spreads. The pipeline and infrastructure business was a stabilizing factor with consistent margins year over year.
Nine Months
During the first nine months of 2008, infrastructure and marketing earnings were 14% higher than the previous year primarily due to higher brokering margins on crude oil and sulphur during the first half of 2008.
Midstream Capital Expenditures
Midstream capital expenditures totalled $112 million in the first nine months of 2008. At the Lloydminster upgrader we spent $76 million, primarily for contingent consideration and facility reliability projects. The remaining $36 million was spent on the pipeline extension between Lloydminster and Hardisty, Alberta.
3.3 Downstream —————————————————————————- Canadian Refined Products Net Earnings Summary Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars, except where indicated) 2008 2007 2008 2007 —————————————————————————- Gross margin – fuel sales $ 30 $ 39 $ 118 $ 144 – ancillary sales 9 12 33 31 – asphalt sales 37 82 84 131 —————————————————————————- 76 133 235 306 Operating and administration expenses 19 19 45 57 Depreciation and amortization 21 16 61 47 Income taxes 11 31 39 62 —————————————————————————- Net earnings $ 25 $ 67 $ 90 $ 140 —————————————————————————- —————————————————————————- Selected operating data: Number of fuel outlets 496 502 Light oil sales (million litres/day) 8.3 9.0 8.0 8.8 Light oil retail sales per outlet(thousand litres/day) 13.4 13.8 13.1 13.2 Prince George refinery throughput (mbbls/day) 7.9 10.8 9.9 10.1 Asphalt sales (mbbls/day) 33.9 25.9 24.9 20.9 Lloydminster refinery throughput (mbbls/day) 27.3 29.0 25.2 24.1 Ethanol production (thousand litres/day) 598.2 323.5 615.7 317.0 —————————————————————————- —————————————————————————-
Canadian Refined Products
Third Quarter
Throughput at the Prince George refinery was 27% lower in the third quarter of 2008 compared with the third quarter of 2007 due to the scheduled shut down in September 2008 for maintenance. Sales volumes were further impacted due to supply shortages from our third party suppliers caused by refinery outages.
Third quarter 2008 ethanol production increased 85% due to the start-up of the Minnedosa ethanol plant, which commenced operations at the end of 2007. This was offset by a 38% reduction in margins in 2008 due to the increase in corn prices, reduced demand and higher natural gas prices.
Asphalt sales volumes were 31% higher in the third quarter of 2008 compared with the same period in 2007 as a result of higher demand and good weather. This was more than offset by a decrease in product margins of approximately 55% due to 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.
Nine Months
During the first nine months of 2008, earnings from gasoline and diesel were lower when compared to the same period in 2007 as a result of the same factors affecting the third quarter. Earnings from ethanol sales were higher than the previous year due to higher sales volume partially offset by lower margins. Margins on asphalt products were lower than those of the same period in the previous year due to rising crude oil feedstock costs.
U.S. Refining and Marketing Net Earnings Summary Three months Nine months ended Sept. 30 ended Sept. 30 (millions of dollars, except where indicated) 2008 2007 2008 2007 —————————————————————————- Gross refining margin $ 105 $ 155 $ 590 $ 155 Processing costs 110 45 269 45 Operating and administration expenses 5 – 7 – Interest – net 1 1 2 1 Depreciation and amortization 42 22 104 22 Income taxes (19) 33 75 33 —————————————————————————- Net earnings $ (34) $ 54 $ 133 $ 54 —————————————————————————- —————————————————————————- Selected operating data: Lima Refinery throughput (mbbls/day) 132.8 140.3 136.4 140.3 (2) Toledo Refinery throughput (mbbls/day) 53.8 – 59.9 (1) – —————————————————————————- —————————————————————————-(1) The Toledo Refinery operating results are included from March 31, 2008, the date the acquisition was completed. Throughput represents six months of operations. (2) The Lima Refinery operating results are included from July 1, 2007, 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 second and third quarters of 2008 are the first periods that the BP/Husky Toledo Refinery’s results of operations have been reflected in our earnings.
Third Quarter
Refining crack spread margins at the start of the quarter were low with pressure on gasoline crack spreads partially offset by firmer distillate spreads. Low gasoline margins resulted in lower crude throughputs at Lima. Crude supply disruptions associated with hurricanes Gustav, Hanna and Ike widened spreads but impacted crude oil feedstock availability. Toledo was also limited in its ability to capitalize on wider sweet/sour differentials as production was impacted by planned process unit outages to complete priority maintenance and turnaround activities.
Nine Months
During the first nine months of 2008, earnings from the U.S. Refining and Marketing segment reflect a full nine months of operations from the Lima Refinery and operations from the Toledo Refinery from April 1, 2008.
In the downstream sector, the drop in demand for motor fuels that began in mid-2007 continued through the first nine months 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. In the third quarter distillate margins continued to be stronger than gasoline margins and we continued to optimize refinery throughput toward distillate production to maximize margins.
Downstream Capital Expenditures
Downstream capital expenditures totalled $155 million during the first nine months of 2008.
In Canada capital expenditures totalled $92 million, $58 million for retail network remodelling, automation and facility upgrades, $18 million for upgrades and environmental protection at the Prince George and Lloydminster refineries, $13 million for upgrades at the Minnedosa and Lloydminster ethanol plants and $3 million for asphalt distribution and processing upgrades.
In the United States capital expenditures totalled $63 million, $28 million at the Lima Refinery for the front-end engineering design for an isocracker debottleneck project and for various environmental protection and facility upgrades. At the Toledo Refinery capital expenditures totalled $35 million primarily for environmental protection and facility upgrades.
3.4 Corporate —————————————————————————- Corporate Summary Three months Nine months ended Sept.30 ended Sept. 30 (millions of dollars) income (expense) 2008 2007 2008 2007 —————————————————————————- Intersegment eliminations – net $ 123 $ 23 $ (14) $ (35) Administration expenses 5 (3) (85) (96) Depreciation and amortization (8) (6) (22) (18) Interest – net (28) (46) (114) (89) Foreign exchange 76 20 60 57 Income taxes (66) 15 42 78 —————————————————————————- Net earnings (loss) $ 102 $ 3 $ (133) $ (103) —————————————————————————- —————————————————————————-
Intersegment eliminations are profit included in inventory that has not been sold to third parties at the end of the period.
In the third quarter of 2008, administration expenses included a stock-based compensation recov