Husky Energy Reports 2007 Annual and Fourth Quarter Results
Husky Energy Inc. is pleased to announce annual net earnings of $3.2 billion or $3.79 per share (diluted), up 18% over the year 2006 from $2.7 billion or $3.21 per share (diluted). Cash flow from operations improved by 21% to $5.4 billion or $6.39 per share (diluted), compared with $4.5 billion or $5.30 per share (diluted) in 2006. Sales and operating revenues, net of royalties, were $15.5 billion in 2007, an increase of 23% over the $12.7 billion in 2006.
“Husky Energy has successfully achieved record performance in all areas of operations: upstream, midstream and downstream,” said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. “With cash flow in excess of $5.4 billion and proved and probable reserves over 3.2 billion barrels of oil equivalent, Husky is well positioned to capitalize on expansion opportunities.”
During the year, Husky progressed a number of significant projects including:
– the purchase of the Lima refinery;
– the agreement with BP to create an integrated oil sands joint venture business;
– the expansion of the Lloydminster upgrader to 82,000 barrels per day;
– the conclusion of negotiations with the Government of Newfoundland and Labrador on fiscal terms for satellite developments at White Rose;
– the finalization of the Madura field gas sale and purchase agreements; and
– the completion of the ethanol plant in Minnedosa.
Husky’s financial position remains strong. Including the acquisition of the Lima refinery, the Company’s debt to capital employed was 19% at December 31, 2007 compared with 14% at December 31, 2006. Debt to cash flow from operations increased to 0.5 times at December 31, 2007 from 0.4 times at December 31, 2006.
Production in 2007 was 377,000 barrels of oil equivalent per day, compared with 360,000 barrels of oil equivalent per day in 2006, an increase of 5%. Crude oil and natural gas liquids production increased 10% to 273,000 barrels per day, compared with 248,000 barrels per day in 2006. Natural gas production was 623 million cubic feet per day, compared with 672 million cubic feet per day in 2006, reflecting Husky’s decision to adjust its drilling program in Western Canada due to weakening gas market conditions and the higher cost environment.
Husky’s 2007 fourth quarter net earnings were $1.1 billion or $1.26 per share (diluted) compared with $542 million or $0.64 per share (diluted) for the fourth quarter of 2006. Net earnings for the fourth quarter of 2007 included a tax benefit of $365 million due to federal tax rate reductions, while there were no similar rate reductions in the fourth quarter of 2006. 2007 fourth quarter cash flow from operations was $1.4 billion or $1.68 per share compared with $1.2 billion or $1.42 per share in the fourth quarter of 2006. Sales and operating revenues, net of royalties, were $4.8 billion in the fourth quarter of 2007, compared with $3.1 billion in the fourth quarter of 2006.
Production for the fourth quarter of 2007 was 367,500 barrels of oil equivalent per day, compared with 376,100 barrels of oil equivalent per day in 2006. Crude oil and natural gas liquids production for the quarter was 264,500 barrels per day, compared with 265,700 barrels per day in 2006. Natural gas production was 617.8 million cubic feet per day, compared with 662.2 million cubic feet per day in 2006 due to a weakening market price for natural gas.
During the quarter, Husky announced a joint venture agreement with BP to create an integrated oil sands joint venture business. Under the terms of the agreement, Husky will contribute its Sunrise assets located in the Athabasca oil sands in northeast Alberta, Canada and BP will contribute its Toledo refinery located in Ohio, USA. The transaction, which is subject to the execution of final agreements and regulatory approval, is expected to close in the first quarter of 2008 with an effective date of January 1, 2008. This transaction will contribute immediate revenue and cash flow and position Husky to move forward with the development of the Sunrise oil sands project.
In December 2007, Husky agreed to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central region of the Athabasca oil sands deposit, for $105 million. This land lies adjacent to oil sands leases currently held by Husky.
Offshore Canada’s East Coast, Husky announced the signing of a binding agreement formalizing the fiscal terms for development of the North Amethyst, West White Rose and South White Rose fields. Under the agreement, the terms of the original White Rose development plan remain unchanged.
Offshore Greenland, Husky and Esso Exploration Greenland Limited (“Esso”) were awarded a joint interest in an exploration licence in West Disko Block 6 (2007/27), which covers an area of 13,213 square kilometres and is located approximately 30 kilometres offshore the west coast of Disko Island. Esso will act as operator of this block. In addition, Husky has an 87.5% interest in two exploration licences, Block 5 and Block 7, covering an area of 21,067 square kilometres that border on Licence 2007/27. Nunaoil A/S, Greenland’s National Oil Company, holds the remaining 12.5% interest in these three licences.
In Indonesia, Husky completed the gas sale and purchase agreements for production from the Madura BD Field. Agreements with PT Parna Raya and PT Inti Alasindo Energy are each for 40 million cubic feet per day while the agreement with PT Perusahaan Gas Negara (Persero) Tbk is for 20 million cubic feet per day. The term of each agreement is 20 years commencing with first production, which is expected in 2011.
Husky has submitted a plan of development to the Government of Indonesia for the Madura development and is in the process of negotiating an extension to the Madura Strait Production Sharing Contract. Contracting for front-end engineering design of offshore facilities and pipelines will commence shortly.
In the Downstream segment, Husky has now completed its integration of the Lima refinery and has taken over all major operations effective February 1, 2008. At the Lima refinery, Husky has commenced its engineering studies to determine the optimal reconfiguration to process a heavier crude oil feedstock.
In the fourth quarter of 2007, Husky completed construction and commenced production at the Minnedosa ethanol plant in Manitoba. The facility will produce annually 130 million litres of ethanol and 130,000 tonnes of Distillers Dried Grain with Solubles (DDGS), a high protein feed supplement. With the completion of the ethanol plants at Lloydminster and Manitoba, Husky is the largest producer and marketer of ethanol in Western Canada.
SUMMARY OF RESULTS ———————————————————- Financial Summary Three months ended (millions of dollars, Dec. 31 Sept. 30 June 30 March 31 except per share amounts and ratios) 2007 2007 2007 2007 ———————————————————- Sales and operating revenues, net of royalties $ 4,760 $ 4,351 $ 3,163 $ 3,244 Segmented earnings Upstream $ 864 $ 516 $ 636 $ 580 Midstream 218 129 77 111 Downstream 103 121 53 20 Corporate and eliminations (111) 3 (45) (61) ———————————————————- Net earnings $ 1,074 $ 769 $ 721 $ 650 ———————————————————- ———————————————————- Per share – Basic and diluted (1) $ 1.26 $ 0.91 $ 0.85 $ 0.77 Cash flow from operations 1,425 1,420 1,257 1,324 Per share – Basic and diluted (1) 1.68 1.67 1.48 1.56 Ordinary quarterly dividend per common share (1) 0.33 0.25 0.25 0.25 Special dividend per common share (1) – – – 0.25 Total assets 21,697 20,718 17,969 17,781 Total long-term debt including current portion 2,814 2,835 1,423 1,527 Return on equity (2) (percent) 30.2 26.6 27.1 32.1 Return on average capital employed (2) (percent) 25.7 22.3 23.8 27.3 ———————————————————- ———————————————————- Three months ended Year ended (millions of dollars, Dec. 31 Sept. 30 June 30 March 31 December 31 except per share amounts and ratios) 2006 2006 2006 2006 2007 2006 —————————————————————————- Sales and operating revenues, net of royalties $ 3,084 $ 3,436 $ 3,040 $ 3,104 $15,518 $12,664 Segmented earnings Upstream $ 453 $ 608 $ 822 $ 412 $ 2,596 $ 2,295 Midstream 105 87 140 150 535 482 Downstream 10 28 52 16 297 106 Corporate and eliminations (26) (41) (36) (54) (214) (157) —————————————————————————- Net earnings $ 542 $ 682 $ 978 $ 524 $ 3,214 $ 2,726 —————————————————————————- —————————————————————————- Per share – Basic and diluted (1) $ 0.64 $ 0.80 $ 1.15 $ 0.62 $ 3.79 $ 3.21 Cash flow from operations 1,207 1,224 1,103 967 5,426 4,501 Per share – Basic and diluted (1) 1.42 1.44 1.30 1.14 6.39 5.30 Ordinary quarterly dividend per common share (1) 0.25 0.25 0.125 0.125 1.08 0.75 Special dividend per common share (1) – – – – 0.25 – Total assets 17,933 17,324 16,326 15,855 21,697 17,933 Total long-term debt including current portion 1,611 1,722 1,722 1,838 2,814 1,611 Return on equity (2) (percent) 31.8 34.2 34.8 29.6 30.2 31.8 Return on average capital employed (2) (percent) 27.0 28.7 28.2 23.2 25.7 27.0 —————————————————————————- —————————————————————————- (1) Reflects a two-for-one share split on June 27, 2007, which has been applied retroactively. Refer to Note 11 to the Consolidated Financial Statements. (2) Calculated for the 12 months ended for the dates shown. Daily Gross Production Three months ended Dec. 31 Sept. 30 June 30 March 31 Dec. 31 2007 2007 2007 2007 2006 —————————————————————————- Crude oil & NGL (mbbls/day) Western Canada Light crude oil & NGL 25.8 25.1 25.3 30.1 30.4 Medium crude oil 27.0 26.7 26.8 27.5 28.0 Heavy crude oil & bitumen 107.8 106.5 105.4 108.0 109.5 —————————————————————————- 160.6 158.3 157.5 165.6 167.9 East Coast Canada White Rose – light crude oil 81.1 79.2 90.3 89.4 79.4 Terra Nova – light crude oil 11.6 16.3 15.5 14.7 6.7 China Wenchang – light crude oil & NGL 11.2 12.7 13.2 13.6 11.7 —————————————————————————- 264.5 266.5 276.5 283.3 265.7 —————————————————————————- Natural gas (mmcf/day) 617.8 620.1 615.7 640.0 662.2 —————————————————————————- Total (mboe/day) 367.5 369.9 379.1 390.0 376.1 —————————————————————————- —————————————————————————- 2008 GUIDANCE AND 2007 ACTUAL —————————————————————————- Gross Production Year ended Original Guidance December 31 Guidance 2008 2007 2007 —————————————————————————- Crude oil & NGL (mbbls/day) Light crude oil & NGL 139-148 139 128-135 Medium crude oil 28- 29 27 28- 30 Heavy crude oil & bitumen 114-124 107 122-130 —————————————————————————- 281-301 273 278-295 Natural gas (mmcf/day) 625-655 623 670-690 Total barrels of oil equivalent (mboe/day) 385-410 377 390-410 —————————————————————————- —————————————————————————- —————————————————————————- Capital Program (1) Year ended Original Guidance December 31 Guidance 2008 2007 2007 —————————————————————————- Upstream Western Canada $ 1,670 $ 1,747 $ 1,840 Oil Sands 300 235 330 East Coast Canada and Frontier 650 279 290 International 430 73 160 —————————————————————————- 3,050 2,334 2,620 Midstream 300 306 380 Downstream 300 223 140 Corporate 50 44 40 —————————————————————————- $ 3,700 $ 2,907 $ 3,180 —————————————————————————- —————————————————————————- (1) Excludes capitalized administration costs, capitalized interest and corporate acquisitions.
MAJOR PROJECTS
UPSTREAM
East Coast Canada Exploration and Delineation
– Production licences for the North Amethyst oil field southwest of White Rose and the South White Rose extension were received in late 2007.
– Delineation of the West White Rose area continued with the completion of the C-30Z well and in the North White Rose area with the completion of the K-03 delineation well.
White Rose and the White Rose Satellite Tie-back Project
– The White Rose South Avalon development plan was completed with the drilling of the second gas injection well in September.
– Front-end engineering design of the North Amethyst satellite tie-back was substantially complete as of December 31, 2007.
– Agreement was reached with the Government of Newfoundland and Labrador regarding fiscal terms for the White Rose satellite fields, including the sale by Husky and its partner of a 5% equity interest to the government.
– The Company has secured the Transocean owned mobile semi-submersible drilling unit GSF Grand Banks for ongoing operations in the White Rose area and for continued exploration and delineation drilling offshore Newfoundland and Labrador. The three year agreement has provisions for two additional one year contract extensions. The GSF Grand Banks has drilled 18 development wells for the White Rose project and has been drilling in offshore Newfoundland and Labrador since 2002.
Tucker Oil Sands Project
The Tucker oil sands project production ramp up has been slower than anticipated largely due to the position of some wells relative to the oil saturation in the reservoir. While optimization strategies are continuing on the original 32 well pairs, the drilling of eight new well pairs on Pad C is complete and a new D pad of eight well pairs is planned.
Sunrise Oil Sands Project
The front-end engineering design for the Sunrise project is complete. Discussions with regulatory authorities to amend our development application is proceeding. Corporate sanction is expected to be in 2008.
The plan for the Sunrise Oil Sands Partnership with BP will proceed in three phases. The first phase will target 60 mbbls/day of bitumen production in 2012. Production is scheduled to reach 200 mbbls/day of bitumen in the 2015 to 2020 period. Preliminary field work is progressing.
Caribou
The overall front-end engineering design has been finalized for the 10 mbbls/day demonstration project and additional technical work is ongoing. Discussions with regulatory authorities are expected to continue into 2008.
Saleski
The winter drilling program has been reduced from 12 to six wells. We are continuing to work on reservoir characterization and assess the technical merit of various recovery processes.
McMullen Oil Sands Acquisition
In December 2007, we executed an agreement to purchase 110,000 contiguous acres of oil sands leases at McMullen, located in the west central Athabasca oil sands deposit, for $105 million. This land lies adjacent to oil sands leases that we currently hold. We will have a 100% working interest in these oil sands leases.
Northwest Territories Exploration
Preparation for winter drilling on Exploration License (“EL”) 423 in the Central Mackenzie Valley is currently underway. EL 423 is located approximately 60 kilometres southeast of the Summit Creek B-44 and the Stewart Creek D-57 discovery wells. The Dahadinni B-20 well is scheduled to commence drilling in early February and the Keele River L-52 well in mid-February with a second rig. Following the acquisition of additional interests from our partners earlier in 2007, we now hold a 75% working interest in this play.
China Exploration
The seismic program over Block 29/26 in the South China Sea, including the Liwan natural gas discovery, was 92% completed but then suspended due to bad weather at the end of October 2007. Delineation drilling of the Liwan area is expected to commence in the second half of 2008 upon the arrival of the West Hercules deep water drilling rig, which is currently being constructed in Korea.
In the shallow waters of East and South China seas, three exploration wells are planned for 2008. The first well is expected to spud in late February on Block 23/15 in the Beibu Wan Basin north of Hainan Island.
Indonesia Natural Gas Development and Exploration
The Plan of Development and production sharing licence extension were submitted to BPMIGAS and MIGAS, the Indonesian regulatory authorities, for approval. On the East Bawean II block we completed the acquisition of 1,400 square kilometres of 3-D seismic data.
Offshore Greenland
Our work programs for 2008 have been finalized and consist of the acquisition of 3,000 kilometres of 2D seismic over Block 6 and 7,000 kilometres of 2D seismic over blocks 5 and 7. Acquisition of the remainder of the hi-resolution aero-gravity and magnetic survey, which was stopped by severe weather conditions, will resume in May 2008.
MIDSTREAM
Lloydminster Pipeline
The Lloydminster to Hardisty, Alberta pipeline expansion project phase one is complete and operational. Phase two is complete and operational with the exception of an 11 kilometre section in and around the City of Lloydminster.
Lloydminster Upgrader
The expansion of the Lloydminster upgrader to 150,000 from 82,000 barrels per day has been deferred due to labour shortages and high costs.
DOWNSTREAM
Lima, Ohio Refinery
Engineering evaluation of several options to reconfigure the Lima, Ohio refinery to increase its capacity to process heavy oil feedstock is underway.
Minnedosa Ethanol Plant
The ethanol plant at Minnedosa, Manitoba, was commissioned in early December 2007. The completion of this plant increases our capacity to produce fuel grade ethanol to 260 million litres per year.
BUSINESS ENVIRONMENT Husky’s financial results are significantly influenced by its business environment. Average quarterly market prices were: —————————————————————————- Average Benchmark Prices and U.S. Exchange Rate Three months ended Dec. 31 Sept. 30 June 30 March 31 Dec. 31 2007 2007 2007 2007 2006 —————————————————————————- WTI crude oil(1) (U.S. $/bbl) 90.68 75.38 65.03 58.16 60.21 Brent crude oil(2) (U.S. $/bbl) 88.70 74.87 68.76 57.75 59.68 Canadian light crude 0.3% sulphur ($/bbl) 87.19 80.70 72.61 67.76 65.12 Lloyd heavy crude oil @ Lloydminster ($/bbl) 42.03 43.61 39.02 38.25 35.24 NYMEX natural gas(1) (U.S. $/mmbtu) 6.97 6.16 7.55 6.77 6.56 NIT natural gas ($/GJ) 5.69 5.31 6.99 7.07 6.03 WTI/Lloyd crude blend differential (U.S. $/bbl) 34.06 23.50 20.36 17.32 21.75 U.S./Canadian dollar exchange rate (U.S. $) 1.018 0.957 0.911 0.854 0.878 —————————————————————————- —————————————————————————- (1) Prices quoted are near-month contract prices for settlement during the next month. (2) Dated Brent prices which are dated less than 15 days prior to loading for delivery.
SENSITIVITY ANALYSIS
The following table indicates the relative annual effect of changes in certain key variables on our pre-tax cash flow and net earnings. The analysis is based on business conditions and production volumes during the fourth quarter of 2007. Each separate item in the sensitivity analysis shows the effect of an increase in that variable only; all other variables are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.
———————————————————————– —– Sensitivity Analysis 2007 Fourth Quarter Effect on Pre-tax Effect on Average Increase Cash Flow (6) Net Earnings (6) —————————————————————————- ($/ ($/ ($ share) ($ share) millions) (7) millions) (7) Upstream and Midstream WTI benchmark crude oil price $90.68 U.S. $1.00/bbl 79 0.09 55 0.06 NYMEX benchmark natural gas price (1) $ 6.97 U.S. $0.20/mmbtu 31 0.04 22 0.03 WTI/Lloyd crude blend differential (2) $34.06 U.S. $1.00/bbl (22) (0.03) (15) (0.02) Exchange rate (U.S. $ per Cdn $) (3) $1.018 U.S. $0.01 (73) (0.09) (52) (0.06) Downstream Light oil margins $ 0.04 Cdn $0.005/litre 16 0.02 10 0.01 Asphalt margins $11.62 Cdn $1.00/bbl 9 0.01 6 0.01 New York Harbor 3:2:1 crack spread (4) $ 8.25 U.S. $1.00/bbl 54 0.06 34 0.04 Consolidated Period end translation of U.S. $ debt (U.S. $ per Cdn $) $1.012(5) U.S. $0.01 18 0.02 —————————————————————————- —————————————————————————- (1) Includes decrease in earnings related to natural gas consumption. (2) Includes impact of upstream and midstream upgrading operations only. (3) Assumes no foreign exchange gains or losses on U.S. dollar denominated long-term debt and other monetary items. (4) Relates to the Lima, Ohio refinery that was acquired on July 1, 2007. (5) U.S./Canadian dollar exchange rate at December 31, 2007. (6) Excludes derivatives. (7) Based on 849.0 million common shares outstanding as of December 31, 2007. RESULTS OF OPERATIONS UPSTREAM —————————————————————————- Upstream Earnings Summary Three months Year ended ended Dec. 31 Dec. 31 (millions of dollars) 2007 2006 2007 2006 —————————————————————————- Gross revenues $ 1,893 $ 1,619 $ 7,287 $ 6,586 Royalties 325 185 1,065 814 —————————————————————————- Net revenues 1,568 1,434 6,222 5,772 Operating and administration expenses 371 373 1,409 1,321 Depletion, depreciation and amortization 396 389 1,615 1,476 Other (13) – (101) – Income taxes (50) 219 703 680 —————————————————————————- Earnings $ 864 $ 453 $ 2,596 $ 2,295 —————————————————————————- —————————————————————————-
Fourth Quarter
Upstream earnings in the fourth quarter of 2007 increased by $411 million compared with the fourth quarter of 2006 mainly as a result of a recovery of future tax expense due to federal rate reductions and higher sales volumes and light crude oil prices from White Rose and Terra Nova.
Twelve Months
Upstream earnings were $301 million higher in 2007 than in 2006 as a result of higher sales volumes of light crude oil from White Rose and Terra Nova and higher crude oil prices offset by lower sales volumes of crude oil and natural gas and lower natural gas prices in Western Canada.
Commodity Prices
The average prices realized during the fourth quarter and twelve months of 2007 compared with the fourth quarter and twelve months of 2006 are illustrated below.
———————————————————————– —– Average Sales Prices Three months Year ended ended Dec. 31 Dec. 31 2007 2006 2007 2006 —————————————————————————- Crude Oil ($/bbl) Light crude oil & NGL 83.43 62.55 73.54 69.06 Medium crude oil 55.37 43.99 51.12 49.48 Heavy crude oil & bitumen 41.13 35.46 40.19 39.92 Total average 63.34 49.43 58.24 54.08 Natural Gas ($/mcf) Average 5.72 6.19 6.19 6.47 —————————————————————————- —————————————————————————-
Unit Operating Costs
Unit operating costs were 1% higher in the fourth quarter of 2007 compared with the same period in 2006.
Unit Depletion, Depreciation and Amortization
Unit depletion, depreciation and amortization expense increased 4% in the fourth quarter of 2007 compared with the same period in 2006 due to a higher capital base and lower reserves used in the depletion calculation.
Other
During the fourth quarter of 2007, a $13 million gain, $101 million gain year-to-date, was recorded on an embedded derivative related to a contract requiring payment in U.S. currency. The payments are expected to occur over the three-year period from mid-2008. This amount will fluctuate with the U.S./Cdn forward exchange rate until the actual contract settlement.
Netback Analysis Three months Year ended ended Dec. 31 Dec. 31 2007 2006 2007 2006 —————————————————————————- $ % $ % $ % $ % (1) (1) (1) (1) Western Canada Crude oil (per boe) (2) Light crude oil Gross price 66.38 53.72 61.02 59.84 Royalties 11.94 18 7.25 13 7.87 13 7.34 12 —————————————————————————- Net sales price 54.44 46.47 53.15 52.50 Operating costs (3) 15.04 23 15.92 30 13.24 22 11.89 20 —————————————————————————- 39.40 30.55 39.91 40.61 —————————————————————————- Medium crude oil Gross price 54.25 43.84 50.42 48.97 Royalties 9.78 18 7.40 17 8.89 18 8.61 18 —————————————————————————- Net sales price 44.47 36.44 41.53 40.36 Operating costs (3) 14.48 27 15.42 35 13.92 28 13.09 27 —————————————————————————- 29.99 21.02 27.61 27.27 —————————————————————————- Heavy crude oil & bitumen Gross price 41.02 35.53 40.14 39.91 Royalties 5.83 14 4.49 13 5.26 13 5.16 13 —————————————————————————- Net sales price 35.19 31.04 34.88 34.75 Operating costs (3) 13.63 33 12.10 34 12.81 32 11.10 28 —————————————————————————- 21.56 18.94 22.07 23.65 —————————————————————————- Natural gas (per mcfge) (4) Gross price 6.17 6.32 6.42 6.65 Royalties 1.16 19 1.20 19 1.23 19 1.37 21 —————————————————————————- Net sales price 5.01 5.12 5.19 5.28 Operating costs (3) 1.41 23 1.39 22 1.39 22 1.18 18 —————————————————————————- 3.60 3.73 3.80 4.10 —————————————————————————- East Coast Light crude oil (per boe) (2) Gross price 85.31 64.62 75.37 71.18 Royalties (5) 14.46 17 1.96 3 9.43 13 1.95 3 —————————————————————————- Net sales price 70.85 62.66 65.94 69.23 Operating costs (3) 3.91 5 4.14 6 4.07 5 5.48 8 —————————————————————————- 66.94 58.52 61.87 63.75 —————————————————————————- Canada Crude oil equivalent (per boe) (2) Gross price 54.10 45.17 51.54 48.48 Royalties 9.11 17 5.17 11 7.46 14 6.00 12 —————————————————————————- Net sales price 44.99 40.00 44.08 42.48 Operating costs (3) 9.78 18 9.76 22 9.28 18 9.01 19 —————————————————————————- 35.21 30.24 34.80 33.47 —————————————————————————- International Light crude oil (per boe) (2) Gross price 89.17 66.01 77.07 73.60 Royalties 24.14 27 10.57 16 15.50 20 12.17 17 —————————————————————————- Net sales price 65.03 55.44 61.57 61.43 Operating costs (3) 4.25 5 4.90 7 3.84 5 3.81 5 —————————————————————————- 60.78 50.54 57.73 57.62 —————————————————————————- Total Crude oil equivalent (per boe) (2) Gross price 55.20 45.83 52.41 49.34 Royalties 9.58 17 5.32 11 7.74 15 6.19 12 —————————————————————————- Net sales price 45.62 40.51 44.67 43.15 Operating costs (3) 9.61 18 9.51 21 9.09 17 8.77 18 —————————————————————————- 36.01 31.00 35.58 34.38 DD&A 11.71 21 11.23 25 11.75 22 11.24 23 Administration expenses & other (3) 0.22 – 0.34 1 (0.17) – 0.48 1 —————————————————————————- Earnings before income taxes 24.08 44 19.43 42 24.00 46 22.66 46 —————————————————————————- 100 100 100 100 —————————————————————————- —————————————————————————- (1) Percent of gross price. (2) Includes associated co-products converted to boe. (3) Operating costs exclude accretion, which is included in administration expenses & other. (4) Includes associated co-products converted to mcfge. (5) During the third quarter of 2007, White Rose royalties increased to 16% because the project, off the East Coast, achieved payout status for Tier 1 royalties. Upstream Capital Expenditures Summary (1) Three months Year ended ended Dec. 31 Dec. 31 (millions of dollars) 2007 2006 2007 2006 —————————————————————————- Exploration Western Canada $ 118 $ 37 $ 456 $ 497 East Coast Canada and Frontier 51 38 84 79 International 24 8 70 77 —————————————————————————- 193 83 610 653 —————————————————————————- Development Western Canada 476 593 1,575 1,675 East Coast Canada 36 28 197 279 International 1 – 6 20 —————————————————————————- 513 621 1,778 1,974 —————————————————————————- $ 706 $ 704 $ 2,388 $ 2,627 —————————————————————————- —————————————————————————- (1) Excludes capitalized costs related to asset retirement obligations incurred during the period. Western Canada Wells Drilled Three months Year ended ended Dec. 31 Dec. 31 2007 2006 2007 2006 Gross Net Gross Net Gross Net Gross Net —————————————————————————- Exploration Oil 23 23 30 29 79 79 101 99 Gas (1) 29 20 52 42 114 92 330 192 Dry 1 – 2 2 14 12 26 24 —————————————————————————- 53 43 84 73 207 183 457 315 —————————————————————————- Development Oil 154 143 210 209 571 530 590 543 Gas (1) 102 56 183 159 343 251 565 490 Dry 12 10 5 5 31 29 25 22 —————————————————————————- 268 209 398 373 945 810 1,180 1,055 —————————————————————————- Total 321 252 482 446 1,152 993 1,637 1,370 —————————————————————————- —————————————————————————- (1) The decrease in the number of gas wells drilled for the year ended December 31, 2007 compared with 2006 reflects weaker gas prices and a fall in the number of coalbed methane wells. MIDSTREAM —————————————————————————- Upgrading Earnings Summary Three months Year ended ended Dec. 31 Dec. 31 (millions of dollars, except where indicated) 2007 2006 2007 2006 —————————————————————————- Gross margin $ 232 $ 145 $ 614 $ 624 Operating costs 61 55 221 224 Other recoveries (1) (2) (4) (6) Depreciation and amortization 8 6 25 24 Income taxes 27 27 90 97 —————————————————————————- Earnings $ 137 $ 59 $ 282 $ 285 —————————————————————————- —————————————————————————- Selected operating data: Upgrader throughput (1) (mbbls/day) 73.1 70.8 61.4 71.0 Synthetic crude oil sales (mbbls/day) 66.5 64.1 53.1 62.5 Upgrading differential ($/bbl) $ 36.74 $ 23.81 $ 30.73 $ 26.16 Unit margin ($/bbl) $ 37.92 $ 24.57 $ 31.67 $ 27.35 Unit operating cost (2) ($/bbl) $ 8.95 $ 8.39 $ 9.83 $ 8.65 —————————————————————————- —————————————————————————- (1) Throughput includes diluent returned to the field. (2) Based on throughput.
Fourth Quarter
Upgrading earnings in the fourth quarter of 2007 were $78 million higher than the fourth quarter of 2006 due to an increased upgrading differential, higher sales volume of synthetic crude oil and a recovery of future tax expense due to federal rate reductions.
Twelve Months
Upgrading earnings in 2007 were $3 million less than 2006 largely due to lower sales volumes due to the 49-day plant turnaround offset by an increase in the upgrading differential.
———————————————————————– —– Infrastructure and Marketing Three months Year ended Earnings Summary ended Dec. 31 Dec. 31 (millions of dollars, except where indicated) 2007 2006 2007 2006 —————————————————————————- Gross margin – pipeline $ 28 $ 24 $ 115 $ 104 – other infrastructure and marketing 87 56 278 208 —————————————————————————- 115 80 393 312 Other expenses 7 3 14 11 Depreciation and amortization 7 7 28 24 Income taxes 20 24 98 80 —————————————————————————- Earnings $ 81 $ 46 $ 253 $ 197 —————————————————————————- —————————————————————————- Selected operating data: Aggregate pipeline throughput (mbbls/day) 497 465 501 475 —————————————————————————- —————————————————————————-
Fourth Quarter
Infrastructure and marketing earnings in the fourth quarter of 2007 increased by $35 million over the same period in 2006 primarily due to higher earnings from sales of blended heavy crude oil, higher crude oil and NGL trading earnings and a recovery of future tax expense due to federal rate reductions.
Twelve Months
Infrastructure and marketing earnings in 2007 increased by $56 million over 2006 primarily due to higher crude oil pipeline margins, higher crude oil and NGL trading earnings, higher earnings from sales of blended heavy crude oil and higher natural gas marketing earnings.
Midstream Capital Expenditures
Midstream capital expenditures totalled $309 million in 2007; $217 million at the Lloydminster Upgrader, primarily for debottleneck and reliability projects and expansion studies and $92 million on pipelines and infrastructure.
DOWNSTREAM ———————————————————— —————- Canadian Refined Products Three months Year ended Earnings Summary ended Dec. 31 Dec. 31 (millions of dollars, except where indicated) 2007 2006 2007 2006 —————————————————————————- Gross margin – fuel sales $ 44 $ 17 $ 188 $ 138 – ancillary sales 11 10 42 36 – asphalt sales 29 23 160 94 —————————————————————————- 84 50 390 268 Operating and other expenses 25 21 82 74 Depreciation and amortization 19 14 66 48 Income taxes (12) 5 50 40 —————————————————————————- Earnings $ 52 $ 10 $ 192 $ 106 —————————————————————————- —————————————————————————- Selected operating data: Number of fuel outlets 505 505 Light oil sales (million litres/day) 8.5 8.6 8.7 8.7 Light oil retail sales per outlet (thousand litres/day) 13.4 12.8 13.2 12.9 Prince George refinery throughput (mbbls/day) 11.6 11.2 10.5 9.0 Asphalt sales (mbbls/day) 24.5 21.0 21.8 23.4 Lloydminster refinery throughput (mbbls/day) 28.8 28.1 25.3 27.1 Ethanol production (thousand litres/day) 347.2 159.3 324.6 59.7 —————————————————————————- —————————————————————————-
Fourth Quarter
Canadian refined products earnings in the fourth quarter of 2007 increased by $42 million over the fourth quarter of 2006 due to higher margins for gasoline and ethanol, higher sales volume for asphalt products and a recovery of future tax expense due to federal rate reductions.
Twelve Months
Canadian refined products earnings in 2007 increased by $86 million over 2006 due to higher margins for gasoline, distillates, ethanol and asphalt and higher sales volume of ethanol products partially offset by higher depreciation created by the startup of the Lloydminster ethanol plant.
———————————————————————– —– U.S. Refining and Marketing Earnings Summary Three months Six months ended Dec. 31 ended Dec. 31 (millions of dollars, except where indicated) 2007 2007 —————————————————————————- Gross refining margin $ 155 $ 310 Processing costs 48 93 Operating and other expenses 1 1 Interest – net – 1 Depreciation and amortization 25 47 Income taxes 30 63 —————————————————————————- Earnings $ 51 $ 105 —————————————————————————- —————————————————————————- Selected operating data: Refinery throughput (mbbls/day) Crude oil and other feedstock 147 144 Yield (mbbls/day) Gasoline 84 82 Middle distillates 52 47 Other fuel and feedstock 13 16 Margins ($/bbl crude throughput) Gross refining margin 11.12 12.42 Unit operating costs ($/bbl of yield) 3.47 3.48 Refined product sales (mbbls/day) Gasoline 87 81 Middle distillates 52 46 Other fuel and feedstock 14 13 —————————————————————————- —————————————————————————-
The Lima refinery had a good fourth quarter meeting expectations and operating normally following the electrical transformer outage in the third quarter.
Downstream Capital Expenditures
Canadian refined products capital expenditures totalled $212 million in 2007; $3 million at the Lloydminster ethanol plant, $114 million at the Minnedosa ethanol plant, $69 million for marketing location upgrades and construction, $17 million for debottleneck and upgrade projects at the Lloydminster asphalt refinery and asphalt distribution facilities and $9 million at the Prince George refinery.
Subsequent to the acquisition of the Lima refinery, capital expenditures at the refinery for the six months ended December 31, 2007 totalled $21 million and were largely for environmental projects and plant upgrades to improve reliability.
CORPORATE ————————————————————- ————— Corporate Summary Three months Year ended ended Dec. 31 Dec. 31 (millions of dollars) income (expense) 2007 2006 2007 2006 —————————————————————————- Intersegment eliminations – net $ (16) $ 36 $ (51) $ 20 Administration expenses (21) (16) (54) (35) Stock-based compensation (40) (35) (88) (138) Accretion – (1) (4) (3) Other – net 6 (4) (5) (23) Depreciation and amortization (7) (10) (25) (27) Interest on debt (46) (27) (148) (125) Interest capitalized 6 3 19 33 Foreign exchange – realized (32) (12) (74) 7 Foreign exchange – unrealized 26 4 125 17 Income taxes 13 36 91 117 —————————————————————————- Earnings (loss) $ (111) $ (26) $ (214) $ (157) —————————————————————————- —————————————————————————- —————————————————————————- Foreign Exchange Summary Three months Year ended ended Dec. 31 Dec. 31 (millions of dollars) 2007 2006 2007 2006 —————————————————————————- (Gain) loss on translation of U.S. dollar denominated long-term debt Realized $ – $ (11) $ – $ (42) Unrealized (9) 71 (197) 35 —————————————————————————- (9) 60 (197) (7) —————————————————————————- Cross currency swaps Realized – 47 – 47 Unrealized 3 (69) 62 (43) —————————————————————————- 3 (22) 62 4 —————————————————————————- Other (gains) losses 12 (30) 84 (21) —————————————————————————- $ 6 $ 8 $ (51) $ (24) —————————————————————————- —————————————————————————- U.S./Canadian dollar exchange rates: At beginning of period U.S. U.S. U.S. U.S. $ 1.004 $ 0.897 $ 0.858 $ 0.858 At end of period U.S. U.S. U.S. U.S. $ 1.012 $ 0.858 $ 1.012 $ 0.858 —————————————————————————- —————————————————————————- Corporate Capital Expenditures Corporate capital expenditures totalled $44 million in 2007 primarily for various office and information system upgrades. ADDITIONAL INFORMATION OIL AND GAS RESERVES —————————————————————————- Reconciliation of Proved Reserves (1) Crude oil & NGL Natural gas Equivalent units (mmbbls) (bcf) (mmboe) —————————————————————————- December 31, 2006 647 2,143 1,004 Revision of previous estimates 25 64 36 Discoveries, extensions and improved recovery 85 199 118 Purchase of reserves in place 1 36 7 Sale of reserves in place (10) (23) (14) Production (99) (228) (137) —————————————————————————- December 31, 2007 649 2,191 1,014 —————————————————————————- —————————————————————————- Proved plus probable reserves December 31, 2007 2,688 3,180 3,218 December 31, 2006 2,006 2,626 2,444 —————————————————————————- —————————————————————————- (1) Constant price before royalties.
NON-GAAP MEASURES
Disclosure of Cash Flow from Operations
This document contains the term “cash flow from operations”, which should not be considered an alternative to, or more meaningful than “cash flow – operating activities” as determined in accordance with generally accepted accounting principles as an indicator of our financial performance. Our determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations equals net earnings plus items not affecting cash which include accretion, depletion, depreciation and amortization, future income taxes, foreign exchange and other non-cash items.
The following table shows the reconciliation of cash flow from operations to cash flow – operating activities for the periods noted: —————————————————————————- Year ended December 31 (millions of dollars) 2007 2006 —————————————————————————- Non-GAAP Cash flow from operations $ 5,426 $ 4,501 Settlement of asset retirement obligations (51) (36) Change in non-cash working capital (718) 544 —————————————————————————- GAAP Cash flow – operating activities $ 4,657 $ 5,009 —————————————————————————- —————————————————————————- Abbreviations bbls barrels bps basis points mbbls thousand barrels mbbls/day thousand barrels per day mmbbls million barrels mcf thousand cubic feet mmcf million cubic feet mmcf/day million cubic feet per day bcf billion cubic feet tcf trillion cubic feet boe barrels of oil equivalent mboe thousand barrels of oil equivalent mboe/day thousand barrels of oil equivalent per day mmboe million barrels of oil equivalent mcfge thousand cubic feet of gas equivalent GJ gigajoule mmbtu million British Thermal Units mmlt million long tons MW megawatt MWh megawatt-hour NGL natural gas liquids WTI West Texas Intermediate NYMEX New York Mercantile Exchange NIT NOVA Inventory Transfer 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 OPEC Organization of Petroleum Exporting Countries WCSB Western Canada Sedimentary Basin SAGD Steam-assisted gravity drainage 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 Carbonate Sedimentary rock primarily composed of calcium carbonate (limestone) or calcium magnesium carbonate (dolomite) which forms many petroleum reservoirs Cash Flow from Earnings from operations plus non-cash charges Operations before settlement of asset retirement obligations and change in non- cash working capital Coalbed Methane Methane (CH4), the principal component of natural gas, is adsorbed in the pores of coal seams Contingent Resource Are those quantities of oil and gas estimated on a given date to be potentially recoverable from known accumulations but not currently economic Dated Brent Prices which are dated less than 15 days prior to loading for delivery Design Rate Capacity Maximum continuous rated output of a plant based on its design Discovered Resource Are those quantities of oil and gas estimated on a given date to be remaining in, plus those quantities already produced from, known accumulations. Discovered resources are divided into economic and uneconomic categories, with the estimated future recoverable portion classified as reserves and contingent resources, respectively 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 reserves/ Production production before deduction of royalties Heads of Agreement A non-binding document that outlines the main issues relevant to a tentative formal agreement Hectare One hectare is equal to 2.47 acres Nameplate Capacity The maximum rated output at which a plant or other equipment was designed and constructed to safely and efficiently operate under specified conditions 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 Polymer A substance which has a molecular structure built up mainly or entirely of many similar units bonded together Possible Reserves Are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved + probable + possible reserves Surfactant A substance that tends to reduce the surface tension of a liquid in which it is dissolved Total Debt Long-term debt including current portion and bank operating loans
FORWARD-LOOKING STATEMENTS OR INFORMATION
Certain statements in this release and Interim Report are forward-looking statements or information (collectively “forward-looking statements”), within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The Company is hereby providing cautionary statements identifying important factors that could cause the Company’s actual results to differ materially from those projected in these forward-looking statements. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result,”"are expected to,”"will continue,”"is anticipated,”"estimated,”"intend,”"plan,”"projection,”"could,”"vision,”"goals,”"objective” and “outlook”) are not historical facts and are forward-looking and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. In particular, forward-looking statements include: the closing of our joint venture agreement with BP, the throughput restriction at White Rose and East Coast seismic acquisition, our production plans for the Tucker in-situ oil sands project, our Sunrise and Caribou oil sands project production plans and development application schedule, our Northwest Territories drilling program, the schedule of our offshore China geophysical and drilling programs, the commencement of production at the Madura BD natural gas and NGL field, the timing for contracting front-end engineering design work for Indonesia, our Minnedosa plant production capability, our work programs for offshore Greenland and our plans to review options in respect of reconfiguring and expanding the Lima refinery. Accordingly, any such forward-looking statements are qualified in their entirety by reference to, and are accompanied by, the factors discussed throughout this release. Among the key factors that have a direct bearing on our results of operations are the nature of our involvement in the business of exploration for, and development and production of crude oil and natural gas reserves and the fluctuation of the exchange rates between the Canadian and United States dollar.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numero