Cash flow from operations in the first quarter was $1,324 million or $3.12 per share (diluted), a 37% increase compared with $967 million or $2.28 per share (diluted) in the same quarter of 2006. Sales and operating revenues, net of royalties, were $3.2 billion in the first quarter of 2007, up 5% compared with $3.1 billion in the first quarter of 2006.
"Husky continues to achieve strong financial results in terms of net earnings, cash flow from operations and production," said Mr. John C.S. Lau, President & Chief Executive Officer, Husky Energy Inc. "We are pleased to have regulatory approval for production rate increases at the White Rose oil field to 140,000 barrels per day. East Coast Canada is a strategic core area for us and we are evaluating opportunities to develop the newly discovered resources from the West White Rose and North Amethyst fields."
In the first quarter of 2007, total production averaged 390,000 barrels of oil equivalent per day, a 10% increase over the 353,600 barrels of oil equivalent per day in the first quarter of 2006. Total crude oil and natural gas liquids production increased 18% to 283,300 barrels per day, compared with 239,400 barrels per day in the first quarter of 2006. Natural gas production was 640.0 million cubic feet per day, down 7% from the same period last year, due primarily to delays in drilling and tie-ins.
Production at the White Rose oil field averaged 89,400 barrels per day net to Husky in the first quarter. With the latest regulatory and government approval, current reservoir capacity of 125,000 barrels per day is expected to increase to 140,000 barrels per day with the completion of a seventh production well in mid-2007.
At the Tucker Oil Sands project, production rates are improving with approximately half of the 32 well pairs in production mode and the remaining well pairs in initial steaming mode. Production rates are expected to reach the target level of 30,000 barrels per day over the next 20 months.
The Sunrise Oil Sands project continues to progress with completion of the front-end engineering design work planned for the end of 2007. Solutions for the transporting, upgrading and refining of the bitumen are proceeding.
At Caribou Lake and Saleski, Husky has completed 2-D and 3-D seismic data and conducted drilling activity to further define the resource at these locations.
Internationally, Husky completed the interpretation of the 3-D seismic data acquired over the Liwan natural gas discovery offshore China. The Company plans to acquire additional seismic over Block 29/26 and the adjacent Block 29/06 later this year. During the first quarter of 2007, we signed an agreement to secure a deep-water drilling rig for a three-year term commencing in mid-2008.
In Indonesia, negotiations for a Gas Sales Agreement and a Madura Production Sharing Contract are progressing. The amended development plan for the Madura BD project will be submitted to regulators for approval once the terms for a Gas Sales Agreement are finalized.
The debottlenecking of the Lloydminster Upgrader from 77,000 barrels per day to 82,000 barrels per day is expected to be complete following a scheduled 40-day turnaround in the second quarter. Front-end engineering design work to double the capacity of the Upgrader to a potential capacity of 150,000 barrels per day continues with work expected to be complete by the end of 2007.
In Minnedosa, construction of the new ethanol production facility is currently 50% complete with commissioning expected in the third quarter of 2007.
Husky continues to strengthen its financial position. Total long-term debt including current portion at March 31, 2007 was $1,527 million, a 5% decrease from $1,611 million at December 31, 2006.
QUARTERLY FINANCIAL RESULTS
Husky's net earnings for the first quarter of 2007 were $650 million, up $126 million or 24% compared with the first quarter of 2006.
Higher earnings in the first quarter of 2007 were mainly due to higher crude oil production from the White Rose and Terra Nova oil fields, higher medium and heavy crude oil prices and higher light refined product margins and sales volume. Positive factors were partially offset by lower natural gas and light crude oil prices and lower Western Canada sales volume of crude oil and natural gas, higher depletion and depreciation expense in the upstream business segment, narrower upgrading differential, higher feedstock costs for asphalt production and higher income taxes.
CORE BUSINESS STRATEGY
In summary, our strategy is to continue to exploit our conventional oil and gas asset base in Western Canada while expanding into new areas with large-scale sustainable growth potential. Our plans include projects in the Alberta oil sands, the basins off the East Coast of Canada, the central Mackenzie River Valley, the South China Sea, Madura Strait and the East Java Sea. Our plans for the Midstream and Refined Products segments involve enhancing performance and capturing new value throughout the value chain by further integrating our operations, optimizing our plant operations and expanding plant and infrastructure where warranted.
WHITE ROSE OIL FIELD
At the end of the first quarter of 2007, the governments of Canada and Newfoundland and Labrador together with the Canada-Newfoundland and Labrador Offshore Petroleum Board ("C-NLOPB") approved our application to increase production at the White Rose oil field to 50 mmbbls annually, with a maximum 140 mbbls/day, subject to several technical conditions that relate to safety, conservation and production control.
Current reservoir capacity of 125 mbbls/day is expected to increase to 140 mbbls/day with the completion of the seventh production well in mid-2007. Allowing for downtime associated with maintenance regulatory inspection, drilling rig movements and well tie-in activities, the White Rose oil field is expected to produce between 120 mbbls/day and 125 mbbls/day on an annual average basis.
An application to tie-in production from the South White Rose extension is currently undergoing regulatory review. Applications to develop the newly discovered resources from the West White Rose and North Amethyst fields are scheduled to be filed with the C-NLOPB in 2008. These developments are expected to result in a significant extension of the production plateau and life of the White Rose oil field.
The front-end engineering design studies to tie-back satellite reservoirs to the SeaRose FPSO have progressed to approximately 30% completion. The scope of these studies has expanded and now includes the South White Rose, North Amethyst and West White Rose oil pools. As a result of the increase in scope, the engineering work is now expected to be completed by the fourth quarter of 2007.
EAST COAST CANADA EXPLORATION AND WHITE ROSE DELINEATION
An additional delineation well is planned for later in 2007 to further define the West White Rose resource.
We are currently evaluating data from our recent 3-D seismic program, which was shot over Exploration Licenses 1067 and 1011, to determine future drilling prospectivity.
TUCKER OIL SANDS PROJECT
During the first quarter, the Tucker Oil Sands project completed its commissioning and start-up phase. Half of the 32 well pairs are in production with the remaining well pairs in initial steaming mode. Production rates are expected to increase to 30,000 barrels per day over the next 20 months.
SUNRISE OIL SANDS PROJECT
The front-end engineering design of the Sunrise Oil Sands project is continuing and is approximately 40% complete. This work is expected to be completed by the fourth quarter of 2007. The first phase of the project will have a design rate of 60 mbbls/day and will ultimately be developed to a production plateau of 200 mbbls/day.
In the field, 29 stratigraphic test wells were drilled, cored and logged. Analysis of the data acquired is now underway. In addition, five additional water source wells and two observation wells were drilled. We also continued discussions and planning with various industry participants in respect of the general area's infrastructure needs. Discussions are continuing with regulatory authorities and stakeholders.
CARIBOU AND SALESKI
At Caribou we drilled 39 stratigraphic test wells, completed a 3-D seismic program and tested and cased two water source and four disposal wells. Engineering work during the quarter included modeling and simulation studies. Discussions and presentations proceeded during the quarter with the Alberta Energy and Utilities Board and several stakeholder groups.
During the first quarter of 2007, we acquired 2,560 acres in the Saleski area bringing our total landholdings in this area to 241,760 acres. Activity at Saleski also included drilling various test wells and gathering of 2-D and 3-D seismic data.
NORTHWEST TERRITORIES EXPLORATION
In the Central Mackenzie Valley where we have new oil and gas exploration prospects at Summit Creek and Stewart Lake, we are currently evaluating seismic data acquired in September 2006. We plan to undertake a drilling program in the winter of 2007/2008 to further appraise these discoveries.
During the first quarter of 2007, we signed an agreement to secure a deep-water rig for three years commencing in 2008. This rig will be used to delineate the Liwan natural gas discovery and undertake further exploratory drilling on Block 29/26 in the South China Sea.
We completed the interpretation of the 3-D seismic that was acquired over Liwan and expect to commence delineation drilling in mid-2008. We also plan to acquire additional seismic data over Block 29/26, which contains Liwan and Block 29/06, a plan precipitated by the initial Liwan data interpretation.
In the East China Sea we are preparing to drill one exploration well on Block 04/35. Our schedule remains to spud this well before the end of the year, contingent on rig availability.
INDONESIA NATURAL GAS DEVELOPMENT AND EXPLORATION
In Indonesia, our negotiations to execute a natural gas sales agreement progressed and we are currently awaiting approval from the Indonesian regulator, BPMIGAS. Our amended development plan for the BD natural gas and condensate field in the Madura Strait will be submitted to BPMIGAS for their approval, once the terms for the gas sales agreement are finalized.
Additionally, preparations are underway to acquire 3-D seismic data on our recently awarded exploration block, East Bawean II.
LLOYDMINSTER TO HARDISTY PIPELINE EXPANSION
The first phase of our pipeline expansion from Lloydminster to Hardisty, Alberta, the intersection with the mainline of the Enbridge Pipeline, was completed in March 2007. The overall project is approximately 73% complete and is on schedule to be finished by the fourth quarter of 2007.
LLOYDMINSTER UPGRADER EXPANSION
The front-end engineering design for the potential expansion of the Lloydminster Upgrader has reached approximately 57% completion. We expect this work will be completed in the fourth quarter of 2007.
MINNEDOSA ETHANOL PLANT
At Minnedosa, the ethanol plant is 50% complete. We expect to commission the plant in the third quarter followed by full operation in the fourth quarter of 2007.
During the first quarter of 2007, our upstream net revenues were $1.6 billion, compared with $1.3 billion in the first quarter of 2006. Our revenues are affected largely by the volatility of oil and gas commodity prices. Our oil and gas production is predominately sold at the prevailing market prices and those prices are subject to the precarious balance between supply and demand on a global scale. A large number of factors can impact perceived supply and demand and those perceptions drive the oil and gas commodity markets up and down, all of which are beyond our control.
In the first quarter of 2007, Western Canada was the source of 58% of our crude oil and 100% of our natural gas production resulting in 59% of upstream revenue before royalties, the East Coast of Canada contributed 37% of our crude oil production, 76% of our light crude oil production and resulted in 36% of upstream revenue before royalties and China contributed 5% of revenue.
In the first quarter of 2006, Western Canada was the source of 71% of our crude oil and 100% of our natural gas production resulting in 70% of upstream revenue before royalties, the East Coast Canada contributed 23% of our crude oil production, 62% of our light crude oil production and resulted in 24% of upstream revenue before royalties and China contributed 6% of revenue.
Crude Oil Production
In the first quarter of 2007, Western Canada crude oil and NGL production declined 3% compared with the first quarter of 2006. Heavy crude oil production accounted for about half of the decrease, particularly from thermal operations, which are currently undergoing optimization and debottleneck work. The remainder of the decline was mainly lower medium crude oil and NGL production which resulted from natural reservoir declines not yet offset by new drilling.
Crude oil production from the White Rose and Terra Nova oil fields off the East Coast of Canada averaged 104.1 mbbls/day during the first quarter of 2007 compared with 55.7 mbbls/day during the first quarter of 2006, an increase of 87%. At White Rose, the productive capacity of the field increased to 125 mbbls/day with the completion of the sixth production well in November 2006. Production at Terra Nova was curtailed during the first quarter of 2006 as a result of protracted mechanical issues, which were resolved in late 2006.
At Wenchang in the South China Sea, production was marginally higher in the first quarter of 2007 compared to the same period in 2006. New production wells and well workovers in the fourth quarter of 2006 boosted production levels in the first quarter of 2007. The installation of gas liquid extraction facilities also augmented crude oil production.
On April 11, 2007, we closed a transaction to dispose of several properties located mainly in northwest Alberta and southwest Saskatchewan with current production of approximately 5,200 boe/day. Total proceeds amounted to $339 million.
Natural Gas Production
All of our natural gas production is from Western Canada. In the first quarter of 2007, the foothills of Alberta and British Columbia, the deep basin of Alberta and the plains of northeast British Columbia and northwest Alberta were the sources of 57% of our natural gas production, the remainder was from the plains throughout Alberta and southwest Saskatchewan.
Production of natural gas was down approximately 7% in the first quarter of 2007 compared with the first quarter of 2006 primarily due to drilling and infrastructure delays, plant restrictions and mechanical related down-time.
Unit Operating Costs
Operating costs in Western Canada averaged $10.55/boe in the first quarter of 2007 compared with $9.31/boe in the same period in 2006. Increasing operating costs in Western Canada are 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, more extensive pipeline systems, crude and water trucking and more extensive natural gas compression systems. These factors in turn require higher energy consumption, workovers and generally more material costs. In addition, higher levels of industry activity lead naturally to competition for resources and consequential higher service rates and unit costs. Our efforts are focused on managing rising operating costs by all means available to us. We strive to keep our infrastructure, including gas plants, crude processing plants, transportation systems, compression systems, lease access and other infrastructure fully utilized.
Operating costs at the East Coast offshore operations averaged $3.03/bbl in the first quarter of 2007 compared with $7.35/bbl in the first quarter of 2006. Unit operating costs in the first quarter of 2007 benefited from higher production volume from both White Rose and Terra Nova.
Operating costs at the South China Sea offshore operations averaged $4.28/bbl in the first quarter of 2007 compared with $3.52/bbl in the same period in 2006. Increased unit operating costs resulted from the maturing of the reservoir and the addition of liquids extraction to the operation.
Depletion, depreciation and amortization ("DD&A") under the full cost method of accounting for oil and gas activities is calculated on a country-by-country basis. The DD&A rate is calculated by dividing the capital costs subject to DD&A by the proved oil and gas reserves expressed as an equivalent barrel. The resultant dollar per barrel of oil equivalent is assigned to each barrel of oil equivalent that is produced to determine the DD&A expense for the period.
Total DD&A averaged $11.37/boe in the first quarter of 2007 compared with $11.03/boe in the first quarter of 2006.
DD&A in Canada averaged $11.37/boe in the first quarter of 2007 compared with $11.26/boe in the first quarter of 2006. The increase in DD&A results primarily from higher capital. Increasing capital is due to increased drilling and associated infrastructure in Western Canada and large capital investment required to develop offshore reserves off the East Coast of Canada.
DD&A in China averaged $11.11/boe in the first quarter of 2007 compared with $8.98/boe in the first quarter of 2006. Increasing unit DD&A results from declining reserve volume due to reservoir depletion.
UPSTREAM CAPITAL EXPENDITURES
Capital expenditures during the first quarter of 2007 were funded primarily with internally generated cash flow.
Our 2007 Upstream Capital expenditure guidance remains unchanged from that reported in our recently filed annual MD&A.
During the first quarter of 2007, capital expenditures were $553 million (90%) in Western Canada, $59 million (9%) off the East Coast of Canada and $5 million (1%) offshore China, Indonesia and other international areas.
In Western Canada, we invested $466 million on exploration and development on conventional areas, which produce variously light, medium, heavy crude oil or natural gas throughout the Western Canada Sedimentary Basin, $272 million of which was invested on properties in Alberta, northeast British Columbia and southern Saskatchewan primarily to further develop properties with proved reserves. We drilled 234 net wells in these regions resulting in 29 oil wells and 139 natural gas wells. In the Lloydminster area of Alberta and Saskatchewan, from which the majority of our heavy crude oil is produced, we invested $139 million, again mainly to extend proved properties. We drilled 128 net wells in the Lloydminster area resulting in 115 oil wells and 10 natural gas wells. Our principal exploration program is conducted along the foothills of Alberta and British Columbia and in the deep basin region of Alberta. In the first quarter of 2007, we invested $55 million drilling in these natural gas prone areas.
During the first quarter of 2007, we drilled five net exploration wells in the foothills/deep basin regions; all were completed natural gas wells.
We spent $87 million in the oil sands areas during the first quarter of 2007, $30 million at Tucker where production is ramping up. We invested $24 million on the Sunrise project. Front-end engineering design is currently underway. We invested $33 million at our other oil sands areas principally at Saleski where we acquired additional lands, began to acquire seismic data and drilled several evaluation wells. We also drilled several stratigraphic test wells, water source and disposal evaluation wells and acquired seismic data at Caribou.
Off the East Coast of Canada
During the first quarter of 2007 capital expenditures in the region off the East Coast of Canada totaled $59 million. We are currently drilling the seventh production well at the White Rose oil field and a delineation well in the south portion of the Far East flank at the Terra Nova oil field. Exploration expenditures in the East Coast offshore areas were minimal during the first quarter of 2007 as drilling locations were being evaluated.
During the first quarter of 2007 we invested $5 million on international exploration for drilling location evaluations for the South and East China Seas and on the East Bawean II exploration block in the Java Sea.
Upgrading earnings in the first quarter of 2007 were $51 million, a decrease of $42 million from the first quarter of 2006 due primarily to reduced light to heavy oil price differential. Upgrader throughput in the first quarter of 2007 was 3% lower than the comparable quarter in 2006 as a result of some unexpected plant outages. Lower upgrader operating costs during the first quarter of 2007, primarily natural gas and other energy related costs, partially offset the effect of the narrow upgrading differential.
MIDSTREAM CAPITAL EXPENDITURES
Midstream capital expenditures totaled $84 million in the first three months of 2007: $48 million at the Lloydminster Upgrader, primarily for front-end engineering design for a proposed expansion, a small debottleneck project and reliability projects. The remaining $36 million was spent on a pipeline extension between Lloydminster and Hardisty, Alberta.
Refined Products earnings in the first quarter of 2007 increased by $4 million compared with the first quarter of 2006 primarily due to increased fuel margins partially offset by higher depreciation created by the start up of the Lloydminster Ethanol Plant and lower gross margin from the asphalt business due to higher heavy crude oil feedstock costs.
REFINED PRODUCTS CAPITAL EXPENDITURES
Refined Products capital expenditures totaled $40 million during the first quarter of 2007. The Minnedosa ethanol plant currently under construction accounted for $27 million, $6 million for marketing location upgrades and construction, $4 million for debottleneck and upgrade projects at the Lloydminster asphalt refinery and the Prince George refinery.
CORPORATE CAPITAL EXPENDITURES
Corporate capital expenditures totaled $5 million in the first three months of 2007 primarily for various office and information system upgrades.
CONSOLIDATED INCOME TAXES
During the first quarter of 2007, consolidated income taxes consisted of $72 million of current taxes and $225 million of future taxes compared with current taxes of $204 million and future taxes of $48 million in the same period of 2006.
The decrease in current taxes and increase in future taxes in the first quarter of 2007 compared with the first quarter of 2006 was due to the deferral of White Rose income.
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