Exhibit 3
HUSKY ENERGY INC.
2002
Management’s Discussion
and Analysis
MANAGEMENT’S DISCUSSION AND ANALYSIS
Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Auditors’ Report included in this Annual Report. The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada. The effect of significant differences between Canadian and United States accounting principles is disclosed in note 16 of the Consolidated Financial Statements. The following discussion and analysis refers primarily to 2002 compared with 2001, unless otherwise indicated. An abridged discussion and analysis of the salient variances between 2001 and 2000 is provided on page 23. All dollar amounts are in millions of Canadian dollars, unless otherwise indicated. The calculation of barrels of oil equivalent (“boe”) and thousands of cubic feet of gas equivalent (“mcfge”) are based on a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. All production volumes quoted are gross, the Company’s working interest share before royalties, and realized prices include the effect of hedging gains and losses, unless otherwise indicated.
Management’s Discussion and Analysis contains the term cash flow from operations, which should not be considered an alternative to, or more meaningful than cash flow from operating activities as determined in accordance with generally accepted accounting principles (“GAAP”) as an indicator of the Company’s financial performance. Husky’s determination of cash flow from operations may not be comparable to that reported by other companies. Cash flow from operations generated by each business segment represents a measurement of financial performance for which each reporting business segment is responsible. The other items required to arrive at cash flow from operating activities are considered to be a corporate responsibility.
Evaluation of Disclosure Controls and Procedures
The Company’s Chief Executive Officer and Chief Financial Officer (its principal executive officer and principal financial officer, respectively) have concluded, based on their evaluation as of a date within 90 days prior to the filing of this Annual Report (the “evaluation date”), that the Company’s disclosure controls and procedures are effective to ensure that information required to be disclosed by it in reports filed or submitted by it under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Security and Exchange Commission’s rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by it in such reports is accumulated and communicated to the Company’s management, including its Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes to Internal Controls and Procedures for Financial Reporting
There have been no significant changes to Husky’s internal controls or in other factors that could significantly affect these controls subsequent to the evaluation date and the filing date of this Annual Report.
Forward-Looking Statements
Certain of the statements set forth under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report including statements which may contain words such as “could”, “expect”, “believe”, “will” and similar expressions and statements relating to matters that are not historical facts are forward-looking and are based upon Husky’s current belief as to the outcome and timing of such future events. There are numerous risks and uncertainties that can affect the outcome and timing of such events, including many factors beyond the control of Husky. These factors include, but are not limited to, the matters described under the heading “Business Environment”. Should one or more of these risks or uncertainties occur, or should any of the underlying assumptions prove incorrect, Husky’s actual results and plans for 2003 and beyond could differ materially from those expressed in the forward-looking statements.
Overview
Husky’s operations are organized into three major business segments:
| | • | | The upstream segment includes the exploration for and the development and production of crude oil and natural gas in Western Canada, offshore the Canadian East Coast and offshore Southern China and other international areas. |
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| | • | | The midstream segment is organized into two reportable business segments; heavy crude oil upgrading operations, and infrastructure and commodity marketing operations. The infrastructure and commodity marketing segment comprises heavy crude oil pipeline and processing operations, natural gas storage, cogeneration operations and crude oil and natural gas marketing. |
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| | • | | The refined products segment consists of refining of crude oil and marketing of refined petroleum products including asphalt products. |
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Year ended December 31 ($ millions,
except per share amounts and production) | | 2002 | | % Change | | 2001(1) | | % Change | | 2000(1) |
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| Net earnings | | $ | 804 | | | | 23 | | | $ | 654 | | | | 49 | | | $ | 438 | |
| | Per share | — Basic | | | 1.88 | | | | 26 | | | | 1.49 | | | | 16 | | | | 1.28 | |
| | | | — Diluted | | | 1.88 | | | | 27 | | | | 1.48 | | | | 16 | | | | 1.28 | |
| Cash flow from operations | | | 2,096 | | | | 8 | | | | 1,946 | | | | 39 | | | | 1,399 | |
| | Per share | — Basic | | | 4.94 | | | | 7 | | | | 4.60 | | | | 8 | | | | 4.26 | |
| | | | — Diluted | | | 4.92 | | | | 8 | | | | 4.57 | | | | 7 | | | | 4.26 | |
| Sales and operating revenues, net of royalties | | | 6,384 | | | | (3 | ) | | | 6,596 | | | | 30 | | | | 5,066 | |
| Daily production, before royalties | | | | | | | | | | | | | | | | | | | | |
| | Light/medium crude oil & NGL(mbbls/day) | | | 125.9 | | | | 12 | | | | 112.0 | | | | 76 | | | | 63.6 | |
| | Lloydminster heavy crude oil(mbbls/day) | | | 79.4 | | | | 21 | | | | 65.4 | | | | 22 | | | | 53.5 | |
| | Natural gas(mmcf/day) | | | 569.2 | | | | (1 | ) | | | 572.6 | | | | 60 | | | | 358.0 | |
| | Barrels of oil equivalent (6:1)(mboe/day) | | | 300.2 | | | | 10 | | | | 272.8 | | | | 54 | | | | 176.8 | |
| (1) | | 2001 and 2000 amounts as restated. Refer to note 3 of the Consolidated Financial Statements. |
![[Bar graph - Net Earnings]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935701.gif)
![[Bar graph - Cash Flow from Operations]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935702.gif)
![[Bar graph - Sales and Operating Revenues]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935703.gif)
Consolidated Results Summary
Total consolidated revenue during 2002 was three percent lower than in 2001 primarily as a result of lower natural gas prices. The effect of lower natural gas prices was most noticeable in the infrastructure and marketing segment with respect to natural gas marketing revenues.
Higher net earnings and cash flow in 2002 compared with 2001 were attributable to increased earnings from:
| | • | | the upstream business segment |
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| | • | | the commodity marketing and infrastructure business segment |
partially offset by lower earnings from:
| | • | | the upgrading business segment |
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| | • | | the refined products business segment |
Upstream
Earnings from the upstream segment increased by $206 million to $688 million in 2002 compared with $482 million in 2001 due to:
| | • | | higher realized oil prices |
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| | • | | higher crude oil production |
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| | • | | lower natural gas royalties |
partially offset by:
| | • | | lower prices for natural gas |
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| | • | | higher operating costs |
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Midstream
Earnings from the midstream segment decreased by $95 million to $161 million in 2002 compared with $256 million in 2001 due to:
| | • | | narrower upgrading differentials |
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| | • | | lower pipeline throughput |
partially offset by:
| | • | | higher oil and gas commodity marketing income |
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| | • | | higher cogeneration income |
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| | • | | lower energy related upgrading operating costs |
Refined Products
Earnings from the refined products segment decreased by $31 million to $32 million in 2002 compared with $63 million in 2001 due to:
| | • | | lower margins on asphalt sales |
partially offset by:
| | • | | improved gasoline and distillate margins |
Corporate
Corporate charges decreased by $70 million to $77 million in 2002 from $147 million in 2001, due to:
| | • | | lower foreign exchange losses on translation of U.S. dollar denominated long-term debt |
partially offset by:
| | • | | higher intersegment profit eliminations |
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| | • | | higher corporate asset depreciation |
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| | • | | higher net interest expense |
Business Environment
Husky’s financial results are significantly influenced by its business environment, in particular, by crude oil and natural gas prices, the costs to find, develop, produce and deliver crude oil and natural gas, the demand for and ability to deliver natural gas, the exchange rate between the Canadian dollar and the U.S. dollar, refined product margins, the demand for Husky’s pipeline capacity, the demand for refined petroleum products, government regulation and the cost of borrowing.
Average Benchmark Prices
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| | | 2002 | | 2001 | | 2000 |
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West Texas Intermediate (“WTI”)(U.S. $/bbl) | | $ | 26.08 | | | $ | 25.97 | | | $ | 30.20 | |
NYMEX natural gas(U.S. $/mmbtu) | | $ | 3.25 | | | $ | 4.38 | | | $ | 3.91 | |
AECO natural gas($/GJ) | | $ | 3.86 | | | $ | 5.97 | | | $ | 4.76 | |
WTI/Lloyd blend differential(U.S. $/bbl) | | $ | 6.47 | | | $ | 10.74 | | | $ | 8.20 | |
U.S./Canadian dollar exchange rate(U.S. $) | | $ | 0.637 | | | $ | 0.646 | | | $ | 0.673 | |
Commodity Prices
Husky’s earnings depend largely on the profitability of its upstream business, which is significantly affected by fluctuations of oil and gas prices. Commodity prices have been, and are expected to be, volatile due to a number of factors beyond Husky’s control. The prices received for the crude oil and NGL sold by Husky are related to the price of crude oil in world markets. Prices for heavy crude oil and other lesser quality crudes trade at a discount or differential to light sweet crude oil.
Average benchmark oil prices were marginally higher during 2002 after rising throughout most of the year. The price for West Texas Intermediate (“WTI”) crude oil began the year at U.S. $21.13/bbl and ended at U.S. $31.21/bbl, averaging U.S. $26.08/bbl for the year, slightly higher than U.S. $25.97/bbl in 2001 and significantly less than the U.S. $30.20/bbl in 2000.
The opposite trend occurred for average heavy crude oil differentials, which averaged U.S. $6.47/bbl for WTI/Lloyd blend during 2002 compared with U.S. $10.74/bbl during 2001. The narrower differential tends to improve Husky’s financial results as the Company’s crude oil production is weighted toward heavier gravity crudes. In periods of wider differentials, Husky’s upgrader offsets some of the effect of lower heavy crude prices. Husky’s realized price for light/medium crude oil and NGL averaged $33.28/bbl in 2002 compared with $27.19/bbl in 2001 and heavy crude oil averaged $26.09/bbl in 2002 compared with $15.85/bbl in 2001.
Toward the end of 2002 the Organization of Petroleum Exporting Countries (“OPEC”) announced cuts to their production that were intended to keep prices within a U.S. $22 and $28/bbl price band. OPEC has maintained their production discipline for the past three years and prices have fluctuated within the price
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band. World crude oil prices increased toward the end of 2002 and into 2003 as a result of a number of events in addition to OPEC’s decision to cut actual production: colder than normal temperatures; uncertainty over the near-term in respect of Iraq; and, the crippling oil industry strikes in Venezuela. On February 11, 2003 WTI was U.S. $35.43/bbl.
The price of natural gas is affected by regional supply and demand factors in North America, particularly those affecting in the United States such as weather patterns, pipeline delivery capacity, the availability of alternative sources of less costly energy supply, inventory levels and general industry activity levels. Periodic imbalances between supply and demand for natural gas are common and result in volatile pricing. The price of natural gas, unlike crude oil, is not subject to the influence of an organization like OPEC.
Natural gas prices realized by Husky are based either on fixed price contracts, spot prices or the New York Mercantile Exchange (“NYMEX”) or other United States or domestic regional market prices. The NYMEX near-month price for natural gas ended 2002 at U.S. $4.79/mmbtu and was U.S. $5.98/mmbtu on February 11, 2003.
WTI and Husky Realized Crude Oil Price
![[Graph]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935704.gif)
NYMEX Natural Gas and Husky Realized Natural Gas Price
![[Graph]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935705.gif)
The margins realized by Husky for refined products are affected by crude oil price fluctuations, which affect refinery feedstock costs, and third-party refined product purchases. Husky’s ability to maintain refined product margins in an environment of higher feedstock costs is contingent upon its ability to pass higher costs on to its customers.
The profitability of Husky’s heavy oil upgrading operations is dependent upon the amount by which revenues from the synthetic crude oil produced exceed the costs of the heavy oil feedstock plus the related operating costs. An increase in the price of blended heavy crude oil feedstock which is not accompanied by an equivalent increase in the price of synthetic crude oil would reduce the profitability of Husky’s
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upgrading operations. Husky has significant crude oil production that trades at a discount to light crude oil, and any negative effect of a narrower differential on upgrading operations would be more than offset by a positive effect on revenues in the upstream segment.
Husky’s portfolio of light, medium and heavy crude oil and natural gas reserves and the efficient operation of its upgrader, refineries and other infrastructure provide opportunities to take advantage of any increases in commodity prices while assisting in managing price volatility.
Foreign Exchange
Husky’s results are affected by the exchange rate between the Canadian and U.S. dollars. The majority of Husky’s revenues are received in U.S. dollars or from the sale of commodities that receive prices determined by reference to U.S. benchmark prices. Accordingly, a change in the value of the Canadian dollar relative to the U.S. dollar has the effect of increasing or decreasing revenues unlike many of Husky’s expenditures, which are in Canadian dollars. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in Husky’s U.S. dollar denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. At December 31, 2002, 78 percent or $2.1 billion of Husky’s long-term debt and capital securities were denominated in U.S. dollars. At the end of 2002, U.S. $20 million of forward foreign exchange collars were in place with an average cap of $1.54 and floor of $1.49. The terms of the collars range from March 2003 to September 2004. The U.S./Cdn. exchange rate at the end of 2002 was $1.58. On January 23, 2003, the Company executed an arrangement under which it swapped its U.S. $150 million 6.875 percent notes due November 2003. The notes were effectively swapped to $229 million 8.5 percent notes, at an effective exchange rate of $1.525. Refer to note 15 of the Consolidated Financial Statements for further disclosure on the Company’s use of derivative financial instruments to manage foreign currency risk.
Interest Rates
Husky is exposed to interest rate fluctuations on its floating rate debt and derivative financial instruments with sensitivity to interest rates. The Company maintains a portion of its total debt in floating rate facilities. The Company will occasionally fix its floating rate debt or create a variable rate for its fixed rate debt using derivative financial instruments.
At December 31, 2002 substantially all of Husky’s outstanding long-term debt was at fixed rates, however U.S. $535 million had been swapped to floating rates at an average of London Inter Bank Offered Rate (“LIBOR”) plus 1.62 percent. These arrangements mature as follows:
| | • | | U.S. $35 million in November 2003 |
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| | • | | U.S. $150 million in November 2006 |
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| | • | | U.S. $200 million in November 2011 |
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| | • | | U.S. $150 million in June 2012 |
In January, 2003 Husky unwound the U.S. $35 million swap due November 2003. The proceeds amounted to $2.0 million and will be recognized in income over the period to November 2003. In addition $200 million of fixed rate debt was swapped into floating rate debt at Canadian Bankers’ Acceptance Rate (“CDOR”) plus 1.75 percent until July 2009.
Husky’s average effective interest rate during 2002 was 6.70 percent before interest rate swaps and 5.48 percent after swaps. Refer to note 15 of the Consolidated Financial Statements for further disclosure on the Company’s use of derivative financial instruments to manage interest rate risk.
Environmental Regulation
Most aspects of Husky’s business are subject to environmental laws and regulations. Similar to other companies in the oil and gas industry, Husky incurs costs for preventive and corrective actions. Changes to regulations could have an adverse effect on Husky’s results of operations and financial condition.
International Operations
Husky’s international operations may be affected by a variety of factors including political and economic developments, expropriation, exchange controls, currency fluctuations, royalty and tax increases, retroactive tax claims, import and export regulations and other foreign laws or policies affecting foreign trade or investment.
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Risk Management
Husky uses derivative financial instruments when deemed appropriate to hedge exposure to changes in the price of crude oil and natural gas and fluctuations in interest rates and foreign currency exchange rates. Husky does not engage in transactions involving derivative financial instruments for trading or other speculative purposes. Refer to note 15 of the Consolidated Financial Statements for further disclosure on the Company’s use of derivative financial instruments.
Business Plan
Husky’s 2003 business plan assumes that:
| | • | | WTI will average U.S. $24.00/bbl and the WTI/Lloyd blend differential will average U.S. $6.25/bbl |
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| | • | | NYMEX natural gas price will average U.S. $3.75/mcf |
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| | • | | the Canadian dollar will average U.S. $0.65 |
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| | • | | U.S. $LIBOR will average 2.50 percent |
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| | • | | Husky’s total production will average 305 to 325 mboe/day. The composition is estimated to be 120 to 130 bbls/day light crude oil & NGL, 85 to 90 mbbls/day heavy crude oil and 580 to 620 mmcf/day natural gas |
Husky plans to invest capital in the following segments in 2003:
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| | | | 2003 |
| Year ended December 31 ($ millions) | | Estimate |
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| Upstream | | | | |
| | Western Canada | | $ | 1,040 | |
| | East Coast Canada | | | 560 | |
| | International | | | 55 | |
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| | | | 1,655 | |
| Midstream | | | 100 | |
| Refined Products | | | 60 | |
| Corporate | | | 25 | |
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| | | $ | 1,840 | |
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Strategic Plan
The 2003 capital program will continue to implement Husky’s long-term strategic plan of increasing reserves and production in the upstream business segment and expansion and optimization of the midstream and refined products businesses.
The light crude oil potential of the Western Canada Sedimentary Basin, although considerable, is diminishing since discovery of large accumulations of light crude oil is becoming less probable. Declining production from Husky’s light and medium crude oil producing properties in Western Canada is planned to be more than offset by further exploitation of heavy oil in the Lloydminster region of Alberta and Saskatchewan, continued development of oil sands potential in Alberta, production from the White Rose offshore project and further increases of production from new projects in China. Activities related to the development of oil sands in 2003 include submission of an environmental impact assessment and project application for the Tucker and Kearl, Alberta in-situ projects and the drilling of more than 200 stratigraphic test wells at Kearl. Activities in China include evaluation of the newly acquired exploration blocks in the South China Sea. The White Rose development project is progressing and a semi-submersible drilling rig has been secured for development drilling in 2002.
The undiscovered natural gas potential of the Western Canada Sedimentary Basin is considered to be very good and is concentrated in the western portion of the basin. Husky’s natural gas production is expected to increase as a result of exploration and development activities concentrated in the foothills and deep basin region west of the fifth meridian in Alberta and British Columbia as well as the northern plains district of Alberta.
During 2003 Husky intends to invest:
| | • | | in excess of $1 billion on upstream capital programs located throughout the Western Canada Sedimentary Basin |
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| | • | | approximately $100 million in the midstream segment primarily for further debottlenecking of the Lloydminster Upgrader |
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| | • | | approximately $60 million in the refined products segment primarily for further upgrading of the marketing outlet system |
Husky has implemented a corporate hedging plan to protect cash flow and earnings in 2003. The most critical aspect of the plan is to hedge commodity price realizations. The parameters of the plan are as follows:
| | • | | crude oil forward sales at a minimum of U.S. $29.00/bbl |
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| | • | | natural gas forward sales at a minimum of U.S. $5.00/mmbtu in non-heating or inventory building months and U.S. $5.25/mmbtu during heating or inventory draw-down months |
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| | • | | no more than 50 percent of annual forecast production will be hedged |
There is no plan currently to hedge the Canadian dollar or crude oil differentials.
At February 14, 2003 the Company had hedged 26 mmbbls of crude oil primarily from April through to December 2003 at an average price of U.S. $29.50/bbl. At February, 14, 2003 the Company had hedged 37 bcf of natural gas primarily in the second and third quarters of 2003 at an average price of U.S. $5.20/mmbtu. This amounts to 34 percent of Husky’s estimated crude oil production and 17 percent of its estimated natural gas production during 2003. In addition, Husky executed a put option program for approximately 3.7 mmbbls from July to December 2003 at a strike price of U.S. $27.00/bbl. The cost of the program was U.S. $6.1 million.
Results of Operations
Upstream
Upstream Earnings Summary
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| Year ended December 31 ($ millions) | | 2002 | | 2001 | | 2000 |
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| Gross revenues | | $ | 3,120 | | | $ | 2,667 | | | $ | 2,055 | |
| Royalties | | | 460 | | | | 502 | | | | 351 | |
| Hedging (gain)/loss | | | (5 | ) | | | — | | | | 155 | |
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| Net revenues | | | 2,665 | | | | 2,165 | | | | 1,549 | |
| Operating and administrative expenses | | | 729 | | | | 648 | | | | 375 | |
| Depletion, depreciation and amortization | | | 851 | | | | 728 | | | | 407 | |
| Income taxes | | | 397 | | | | 307 | | | | 315 | |
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| Earnings | | $ | 688 | | | $ | 482 | | | $ | 452 | |
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Net Revenue Variance Analysis
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| | | | Light/ | | Lloyd- | | | | | | | | | | | | |
| | | | Medium | | minster | | | | | | | | | | | | |
| | | | Crude Oil | | Heavy | | Natural | | | | | | | | |
| ($ millions) | | & NGL | | Crude Oil | | Gas | | Other | | Total |
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| Year ended December 31, 2000 | | | | | | | | | | | | | | | | | | | | |
| Net revenues | | $ | 632 | | | $ | 357 | | | $ | 534 | | | $ | 26 | | | $ | 1,549 | |
| | Price changes | | | (348 | ) | | | (253 | ) | | | 59 | | | | (8 | ) | | | (550 | ) |
| | Volume changes | | | 632 | | | | 114 | | | | 404 | | | | — | | | | 1,150 | |
| | Royalties | | | (52 | ) | | | 29 | | | | (128 | ) | | | — | | | | (151 | ) |
| | Hedging | | | 49 | | | | 102 | | | | 4 | | | | — | | | | 155 | |
| | Processing | | | — | | | | — | | | | — | | | | 12 | | | | 12 | |
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| Year ended December 31, 2001 | | | | | | | | | | | | | | | | | | | | |
| Net revenues | | | 913 | | | | 349 | | | | 873 | | | | 30 | | | | 2,165 | |
| | Price changes | | | 276 | | | | 297 | | | | (342 | ) | | | 8 | | | | 239 | |
| | Volume changes | | | 138 | | | | 81 | | | | (7 | ) | | | — | | | | 212 | |
| | Royalties | | | (16 | ) | | | (56 | ) | | | 113 | | | | — | | | | 41 | |
| | Hedging | | | 5 | | | | — | | | | — | | | | — | | | | 5 | |
| | Processing | | | — | | | | — | | | | — | | | | 3 | | | | 3 | |
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Year ended December 31, 2002 | | | | | | | | | | | | | | | | | | | | |
Net revenues | | $ | 1,316 | | | $ | 671 | | | $ | 637 | | | $ | 41 | | | $ | 2,665 | |
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Daily Production, Before Royalties
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| Year ended December 31 | | 2002 | | 2001 | | 2000 |
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Light/medium crude oil & NGL(mbbls/day) | | | 125.9 | | | | 112.0 | | | | 63.6 | |
Lloydminster heavy crude oil(mbbls/day) | | | 79.4 | | | | 65.4 | | | | 53.5 | |
Natural gas(mmcf/day) | | | 569.2 | | | | 572.6 | | | | 358.0 | |
Barrels of oil equivalent (6:1)(mboe/day) | | | 300.2 | | | | 272.8 | | | | 176.8 | |
Average Realized Prices
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| Year ended December 31 | | 2002 | | 2001 | | 2000 |
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Light/medium crude oil & NGL($/bbl) | | $ | 33.16 | | | $ | 27.19 | | | $ | 35.88 | |
| Hedging (gain)/loss | | | (0.12 | ) | | | — | | | | 2.46 | |
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| Light/medium crude oil & NGL price realized | | $ | 33.28 | | | $ | 27.19 | | | $ | 33.42 | |
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Lloydminster heavy crude oil($/bbl) | | $ | 26.09 | | | $ | 15.85 | | | $ | 26.45 | |
| Hedging (gain)/loss | | | — | | | | — | | | | 5.19 | |
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| Lloydminster heavy crude oil price realized | | $ | 26.09 | | | $ | 15.85 | | | $ | 21.26 | |
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Natural gas price($/mcf) | | $ | 3.83 | | | $ | 5.47 | | | $ | 5.18 | |
| Hedging (gain)/loss | | | — | | | | — | | | | 0.02 | |
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| Natural gas price realized | | $ | 3.83 | | | $ | 5.47 | | | $ | 5.16 | |
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Product Mix
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| Year ended December 31 | | 2002 | | 2001 | | 2000 |
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| Percentage of upstream sales revenues, after royalties | | | | | | | | | | | | |
| Light/medium crude oil & NGL | | | 49 | % | | | 42 | % | | | 40 | % |
| Lloydminster heavy crude oil | | | 25 | % | | | 16 | % | | | 23 | % |
| Natural gas | | | 26 | % | | | 42 | % | | | 37 | % |
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| | | | 100 | % | | | 100 | % | | | 100 | % |
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Royalty Rates
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| Year ended December 31 | | 2002 | | 2001 | | 2000 |
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| Percentage of upstream sales revenues, before royalties | | | | | | | | | | | | |
| Light/medium crude oil & NGL | | | 15 | % | | | 19 | % | | | 20 | % |
| Lloydminster heavy crude oil | | | 11 | % | | | 8 | % | | | 15 | % |
| Natural gas | | | 18 | % | | | 23 | % | | | 19 | % |
| Total | | | 15 | % | | | 19 | % | | | 19 | % |
2002 compared with 2001
Husky’s earnings from the upstream segment increased by $206 million (43 percent) to $688 million in 2002 from $482 million in 2001.
Page 8
Husky’s total revenues from upstream operations were $3,120 million in 2002 compared with $2,667 million in 2001 as a result of:
| | • | | higher sales volume and price realization for crude oil |
the effect of which was offset partially by:
| | • | | lower natural gas prices |
Higher production volumes of crude oil were due to:
| | • | | the ongoing Lloydminster heavy oil development programs |
| |
| | • | | Terra Nova and Wenchang commencing production in January and July, respectively |
Operating costs per unit of production increased three percent in 2002 compared with 2001 as a result of:
| | • | | light/medium crude oil properties under secondary and tertiary recovery schemes in Western Canada |
| |
| | • | | extensive shallow gas production in Western Canada |
partially offset by:
| | • | | lower unit operating costs at Terra Nova, Wenchang and at the heavy oil operations at Lloydminster |
Depletion, depreciation and amortization (“DD&A”) increased to $7.76/boe in 2002 from $7.31/boe in 2001 and resulted from:
| | • | | higher maintenance capital for properties under secondary and tertiary recovery and shallow natural gas and offshore operations requiring large infrastructure capital |
Income taxes increased in 2002 compared with 2001 reflecting higher pre-tax earnings offset in part by rate reductions in British Columbia and Alberta.
Daily production, before Royalties
![[Bar Graph - Total]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935706.gif)
![[Bar Graph - Light-Medium Crude Oil and NGL]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935707.gif)
![[Bar Graph - Lloydminster Heavy Crude Oil]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935708.gif)
![[Bar Graph - Natural Gas]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935709.gif)
Page 9
Operating Netbacks(1)
Western Canada
Light/Medium Crude Oil Netbacks(2)
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Sales revenues | | $ | 31.10 | | | $ | 27.39 | | | $ | 35.68 | |
| Royalties | | | 5.25 | | | | 4.87 | | | | 6.42 | |
| Hedging (gain)/loss | | | (0.15 | ) | | | — | | | | 2.46 | |
| Operating costs | | | 8.50 | | | | 7.47 | | | | 6.23 | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 17.50 | | | $ | 15.05 | | | $ | 20.57 | |
| | | |
| | | |
| | | |
| |
Lloydminster Heavy Crude Oil Netbacks(2)
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Sales revenues | | $ | 26.02 | | | $ | 16.00 | | | $ | 26.45 | |
| Royalties | | | 2.97 | | | | 1.27 | | | | 3.00 | |
| Hedging (gain)/loss | | | — | | | | — | | | | 5.19 | |
| Operating costs | | | 7.03 | | | | 7.60 | | | | 6.15 | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 16.02 | | | $ | 7.13 | | | $ | 12.11 | |
| | | |
| | | |
| | | |
| |
Natural Gas Netbacks(3)
| | | | | | | | | | | | | |
| Year ended December 31 (per mcfge) | | 2002 | | 2001 | | 2000 |
|
|
|
|
| Sales revenues | | $ | 3.96 | | | $ | 5.39 | | | $ | 5.28 | |
| Royalties | | | 0.82 | | | | 1.30 | | | | 1.18 | |
| Hedging (gain)/loss | | | — | | | | — | | | | 0.02 | |
| Operating costs | | | 0.70 | | | | 0.58 | | | | 0.49 | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 2.44 | | | $ | 3.51 | | | $ | 3.59 | |
| | | |
| | | |
| | | |
| |
Total Western Canada Upstream Netbacks(2)
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Sales revenues | | $ | 27.04 | | | $ | 26.42 | | | $ | 31.41 | |
| Royalties | | | 4.45 | | | | 5.04 | | | | 5.42 | |
| Hedging (gain)/loss | | | (0.05 | ) | | | — | | | | 2.40 | |
| Operating costs | | | 6.55 | | | | 6.08 | | | | 5.27 | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 16.09 | | | $ | 15.30 | | | $ | 18.32 | |
| | | |
| | | |
| | | |
| |
Terra Nova Light/Medium Crude Oil Netbacks
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
|
|
|
|
| Sales revenues | | $ | 35.47 | | | $ | — | | | $ | — | |
| Royalties | | | 0.36 | | | | — | | | | — | |
| Operating costs | | | 3.62 | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 31.49 | | | $ | — | | | $ | — | |
| | | |
| | | |
| | | |
| |
| (1) | | 2001 and 2000 amounts as restated. Refer to note 3 of the Consolidated Financial Statements. |
| |
| (2) | | Includes associated co-products converted to boe. |
| |
| (3) | | Includes associated co-products converted to mcfge. |
| |
Page 10
Wenchang Light/Medium Crude Oil Netbacks
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Sales revenues | | $ | 44.36 | | | $ | — | | | $ | — | |
| Royalties | | | 2.65 | | | | — | | | | — | |
| Operating costs | | | 2.15 | | | | — | | | | — | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 39.56 | | | $ | — | | | $ | — | |
| | | |
| | | |
| | | |
| |
Total Upstream Netbacks(1)
| | | | | | | | | | | | | |
| Year ended December 31 (per boe) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Sales revenues | | $ | 28.12 | | | $ | 26.42 | | | $ | 31.41 | |
| Royalties | | | 4.20 | | | | 5.04 | | | | 5.42 | |
| Hedging (gain)/loss | | | (0.05 | ) | | | — | | | | 2.40 | |
| Operating costs | | | 6.24 | | | | 6.08 | | | | 5.27 | |
| | | |
| | | |
| | | |
| |
| Netback | | $ | 17.73 | | | $ | 15.30 | | | $ | 18.32 | |
| | | |
| | | |
| | | |
| |
| (1) | | Includes associated co-products converted to boe. |
Upstream Capital Expenditures
| | | | | | | | | | | | | | |
| Year ended December 31 ($ millions) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Exploration | | | | | | | | | | | | |
| | Western Canada | | $ | 304 | | | $ | 236 | | | $ | 118 | |
| | East Coast Canada | | | 41 | | | | 81 | | | | 63 | |
| | International | | | 9 | | | | 5 | | | | — | |
| | | |
| | | |
| | | |
| |
| | | | 354 | | | | 322 | | | | 181 | |
| | | |
| | | |
| | | |
| |
| Development | | | | | | | | | | | | |
| | Western Canada | | | 730 | | | | 786 | | | | 301 | |
| | East Coast Canada | | | 417 | | | | 110 | | | | 131 | |
| | International | | | 66 | | | | 99 | | | | 87 | |
| | | | 1,213 | | | | 995 | | | | 519 | |
| | | |
| | | |
| | | |
| |
| | | $ | 1,567 | | | $ | 1,317 | | | $ | 700 | |
| | | |
| | | |
| | | |
| |
Western Canada
Capital expenditures reflect exploration and exploitation of properties in central and southern Alberta, southern Saskatchewan, the foothills, deep basin and northern region of Alberta and north eastern British Columbia and the increasing pace of development in the Lloydminster heavy oil area. Many of the properties located in Alberta and Saskatchewan are crude oil properties under secondary pressure maintenance schemes or shallow natural gas properties, which require extensive optimization and rationalization.
Capital expenditures in the Lloydminster heavy oil areas of Alberta and Saskatchewan in the last two years were $273 million and $324 million, respectively. Husky drilled 369 wells in the Lloydminster area in 2002 compared with 490 wells in 2001 resulting in 327 and 415 oil well completions and 25 and 39 natural gas well completions in 2002 and 2001, respectively. In 2002, expansion of the heavy oil thermal project at Bolney/Celtic, Saskatchewan continued. Capital spending on the project totalled $36 million and productive capacity had been increased from 3,000 bbls/day to 5,000 bbls/day by year-end. Capital spending for the natural gas development in the Shackleton area of southern Saskatchewan totalled $61 million and 2002 exit production volume was approximately 30 mmcf/day.
Exploration spending in Western Canada increased by $68 million to $304 million in 2002 from $236 million in 2001 and $118 million in 2000. Exploration spending remains focused on natural gas prone areas in the deep basin areas of western Alberta and the foothills and northern plains of Alberta and British Columbia.
Page 11
East Coast Canada
Husky’s 2002 capital spending in the Jeanne d’Arc Basin totalled $458 million. Capital spending on the White Rose development project amounted to $395 million (including $24 million of capitalized interest). The Terra Nova oil field development was commissioned in January 2002. Additional development capital spending for Terra Nova amounted to $22 million during the year. The remaining $41 million was for other Jeanne d’Arc Basin exploration.
International
Internationally, Husky’s capital expenditures totalled $75 million during 2002, $66 million of which was spent on the Wenchang oil field development in the South China Sea. Wenchang was commissioned in July 2002. The remainder was spent on an exploration program in the South China Sea, which began in late 2002. The Qionghai 18-1-3 well in the South China Sea was plugged and abandoned in January 2003 without testing and the Wenchang 8-1-1 was plugged and abandoned without testing in February, 2003.
Reserve Additions
The efficient replacement of the Company’s oil and gas productive capacity is the fundamental key to the growth of value. During the three years ended December 31, 2002, Husky has replaced an average of 120 percent of production on a boe basis, exclusive of acquisitions and divestitures. Over the three years ended December 31, 2002 reserves were added at an average cost of $10.12/boe.
During 2002, extensions of proved acreage and improved recovery added 44 mmbbls to proved reserves of crude oil and NGL, 19 mmbbls of which was from Terra Nova. Technical revisions added 12 mmbbls to crude oil and NGL reserves, primarily from Bolney/Celtic. Net divestitures amounted to 11 mmbbls. During 2002 discoveries, extensions and improved recovery added 387 bcf to proved reserves of natural gas. The larger additions were 133 bcf from Boyer in northern Alberta, 82 bcf from Shackleton in southern Saskatchewan and 36 bcf from discoveries in Kiskiu and Ansell in the Alberta foothills and deep basin. Net divestitures of non-core properties amounted to 13 bcf and technical revisions amounted to negative 37 bcf.
At December 31, 2002, the present value of future net cash flows after tax from the Company’s proved oil and gas reserves, based on prices and costs in effect at year-end and discounted at 10 percent, was $7.2 billion compared with $2.8 billion at the end of 2001.
McDaniel & Associates Consultants Ltd., an independent firm of oil and gas reserves evaluation engineers was engaged to evaluate 65 percent of Husky’s proved oil and gas reserves. The firm’s aggregate proved reserve estimates were approximately 10 percent lower than Husky’s estimates which are set out below.
Summary of Reserves
Light/Medium Crude Oil & NGL Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2002 | | 2001 | | 2000 |
| | |
| |
| |
|
| Year ended December 31 (mmbbls) | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
| |
| |
|
| Proved developed | | | 323 | | | | 280 | | | | 329 | | | | 287 | | | | 338 | | | | 283 | |
| Proved undeveloped | | | 65 | | | | 52 | | | | 101 | | | | 89 | | | | 102 | | | | 88 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total proved | | | 388 | | | | 332 | | | | 430 | | | | 376 | | | | 440 | | | | 371 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Lloydminster Heavy Crude Oil Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2002 | | 2001 | | 2000 |
| | |
| |
| |
|
| Year ended December 31 (mmbbls) | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
| |
| |
|
| Proved developed | | | 116 | | | | 109 | | | | 96 | | | | 92 | | | | 65 | | | | 63 | |
| Proved undeveloped | | | 65 | | | | 60 | | | | 73 | | | | 72 | | | | 49 | | | | 47 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total proved | | | 181 | | | | 169 | | | | 169 | | | | 164 | | | | 114 | | | | 110 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Page 12
Natural Gas Reserves
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2002 | | 2001 | | 2000 |
| | |
| |
| |
|
| Year ended December 31 (bcf) | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
| |
| |
|
| Proved developed | | | 1,547 | | | | 1,273 | | | | 1,577 | | | | 1,342 | | | | 1,580 | | | | 1,276 | |
| Proved undeveloped | | | 548 | | | | 440 | | | | 389 | | | | 332 | | | | 329 | | | | 269 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total proved | | | 2,095 | | | | 1,713 | | | | 1,966 | | | | 1,674 | | | | 1,909 | | | | 1,545 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Barrels of Oil Equivalent
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2002 | | 2001 | | 2000 |
| | |
| |
| |
|
| Year ended December 31 (mmboe) | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
| |
| |
|
| Proved developed | | | 697 | | | | 601 | | | | 688 | | | | 603 | | | | 666 | | | | 559 | |
| Proved undeveloped | | | 221 | | | | 185 | | | | 239 | | | | 216 | | | | 206 | | | | 180 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total proved | | | 918 | | | | 786 | | | | 927 | | | | 819 | | | | 872 | | | | 739 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Reserve Life Index(1)
| | | | | | | | | | | | | |
| Year ended December 31 (years) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Light/medium crude oil & NGL | | | 8.5 | | | | 10.5 | | | | 10.2 | |
| Lloydminster heavy crude oil | | | 6.2 | | | | 7.0 | | | | 5.4 | |
| Natural gas | | | 10.0 | | | | 9.4 | | | | 9.0 | |
| Barrels of oil equivalent | | | 8.4 | | | | 9.3 | | | | 8.7 | |
| (1) | | Includes total proved reserves. |
Gross Proved Reserves
![[Bar Graph - Light Medium Crude Oil and NGL]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935710.gif)
![[Bar Graph - Lloydminster Heavy Crude Oil]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935711.gif)
![[Bar Graph - Natural Gas]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935712.gif)
Finding and Development Costs
Total(1)
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Total capitalized costs($ millions) | | $ | 3,314.9 | | | $ | 1,505.1 | | | $ | 1,172.0 | | | $ | 637.8 | |
Proved reserve additions and revisions(mmboe) | | | 327.6 | | | | 114.5 | | | | 120.4 | | | | 92.7 | |
| Average cost per boe | | $ | 10.12 | | | $ | 13.14 | | | $ | 9.73 | | | $ | 6.88 | |
| (1) | | Excludes acquisitions/divestitures. |
Page 13
Western Canada(2)
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Total capitalized costs($ millions) | | $ | 2,298.7 | | | $ | 978.5 | | | $ | 920.1 | | | $ | 400.1 | |
Proved reserve additions and revisions(mmboe) | | | 256.9 | | | | 94.8 | | | | 112.9 | | | | 49.2 | |
| Average cost per boe | | $ | 8.95 | | | $ | 10.32 | | | $ | 8.15 | | | $ | 8.13 | |
| (2) | | Excludes oil sands and acquisitions/divestitures. |
Production Replacement
Total
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Production(mmboe) | | | 273.9 | | | | 109.6 | | | | 99.6 | | | | 64.7 | |
Proved reserve additions and revisions(mmboe) | | | 327.6 | | | | 114.5 | | | | 120.4 | | | | 92.7 | |
Production replacement ratio (excluding acquisitions/divestitures)(percent) | | | 120 | | | | 104 | | | | 121 | | | | 143 | |
Proved reserve additions and revisions (including acquisitions/divestitures)
(mmboe)(1) | | | 372.6 | | | | 100.9 | | | | 154.5 | | | | 117.2 | |
Production replacement ratio (including acquisitions/divestitures)(percent)(1) | | | 136 | | | | 92 | | | | 155 | | | | 181 | |
Western Canada(2)
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Production(mmboe) | | | 264.3 | | | | 100.2 | | | | 99.5 | | | | 64.6 | |
Proved reserve additions and revisions(mmboe) | | | 256.9 | | | | 94.8 | | | | 112.9 | | | | 49.2 | |
Production replacement ratio (excluding acquisitions/divestitures)(percent) | | | 97 | | | | 95 | | | | 113 | | | | 76 | |
Proved reserve additions and revisions (including acquisitions/divestitures)
(mmboe)(1) | | | 301.9 | | | | 81.2 | | | | 147.0 | | | | 73.7 | |
Production replacement ratio (including acquisitions/divestitures)(percent)(1) | | | 114 | | | | 81 | | | | 148 | | | | 114 | |
| (1) | | Excludes 2000 Renaissance acquisition. |
| |
| (2) | | Excludes oil sands. |
Recycle Ratio
The recycle ratio measures the efficiency of Husky’s capital program by comparing the cost of finding and developing proved reserves with the netback from production. The ratio is calculated by dividing the netback by the proved finding and development cost on a boe basis. Netback is defined as upstream net sales revenues less operating and administrative costs per boe of production.
Total
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Netback($/boe) | | $ | 16.89 | | | $ | 17.66 | | | $ | 15.23 | | | $ | 18.15 | |
Proved finding and development cost($/boe) | | $ | 10.12 | | | $ | 13.14 | | | $ | 9.73 | | | $ | 6.88 | |
| Recycle ratio | | | 1.67 | | | | 1.34 | | | | 1.57 | | | | 2.64 | |
Page 14
Western Canada(1)
| | | | | | | | | | | | | | | | | |
| Year ended December 31 | | 2000-2002 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
| |
|
Netback($/boe) | | $ | 16.29 | | | $ | 16.07 | | | $ | 15.21 | | | $ | 18.30 | |
Proved finding and development cost($/boe) | | $ | 8.95 | | | $ | 10.32 | | | $ | 8.15 | | | $ | 8.13 | |
| Recycle ratio | | | 1.82 | | | | 1.56 | | | | 1.87 | | | | 2.25 | |
Western Canada Drilling
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | 2002 | | 2001 | | 2000 |
| | | | |
| |
| |
|
| Year ended December 31 (wells) | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
| |
| |
|
| Exploration | Oil | | | 21 | | | | 20 | | | | 78 | | | | 76 | | | | 16 | | | | 13 | |
| | | Gas | | | 139 | | | | 131 | | | | 102 | | | | 90 | | | | 30 | | | | 20 | |
| | | Dry | | | 15 | | | | 14 | | | | 36 | | | | 34 | | | | 9 | | | | 9 | |
| | | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | | 175 | | | | 165 | | | | 216 | | | | 200 | | | | 55 | | | | 42 | |
| | | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Development | Oil | | | 497 | | | | 453 | | | | 594 | | | | 542 | | | | 411 | | | | 363 | |
| | | Gas | | | 485 | | | | 453 | | | | 251 | | | | 221 | | | | 92 | | | | 70 | |
| | | Dry | | | 58 | | | | 55 | | | | 68 | | | | 63 | | | | 30 | | | | 28 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | 1,040 | | | | 961 | | | | 913 | | | | 826 | | | | 533 | | | | 461 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
| Total | | | 1,215 | | | | 1,126 | | | | 1,129 | | | | 1,026 | | | | 588 | | | | 503 | |
| | | |
| | | |
| | | |
| | | |
| | | |
| | | |
| |
Undeveloped Land Holdings
| | | | | | | | | | | | | | | | | | |
| | | | 2002 | | 2001 |
| | | |
| |
|
| Year ended December 31 (thousands of acres) | | Gross | | Net | | Gross | | Net |
| |
| |
| |
| |
|
| Western Canada | | | | | | | | | | | | | | | | |
| | Alberta | | | 5,416 | | | | 4,907 | | | | 5,980 | | | | 5,373 | |
| | Saskatchewan | | | 2,098 | | | | 1,986 | | | | 2,066 | | | | 1,921 | |
| | British Columbia | | | 314 | | | | 273 | | | | 188 | | | | 141 | |
| | Manitoba | | | 13 | | | | 13 | | | | 76 | | | | 75 | |
| | | |
| | | |
| | | |
| | | |
| |
| | | | 7,841 | | | | 7,179 | | | | 8,310 | | | | 7,510 | |
| Northwest Territories and Arctic | | | 463 | | | | 175 | | | | 1,538 | | | | 409 | |
| Eastern Canada | | | 2,414 | | | | 2,104 | | | | 1,878 | | | | 1,471 | |
| | | |
| | | |
| | | |
| | | |
| |
| Total Canada | | | 10,718 | | | | 9,458 | | | | 11,726 | | | | 9,390 | |
| International | | | 4,464 | | | | 2,066 | | | | 1,425 | | | | 697 | |
| | | |
| | | |
| | | |
| | | |
| |
| Total | | | 15,182 | | | | 11,524 | | | | 13,151 | | | | 10,087 | |
| | | |
| | | |
| | | |
| | | |
| |
Page 15
Results of Operations
Midstream
Upgrading Earnings Summary
| | | | | | | | | | | | | |
| Year ended December 31 ($ millions, except where indicated) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Gross margin | | $ | 246 | | | $ | 428 | | | $ | 321 | |
| Operating costs | | | 154 | | | | 192 | | | | 158 | |
| Other expenses (recoveries) | | | (6 | ) | | | (12 | ) | | | 5 | |
| DD&A | | | 18 | | | | 17 | | | | 16 | |
| Income taxes | | | 26 | | | | 73 | | | | 54 | |
| | | |
| | | |
| | | |
| |
| Earnings | | $ | 54 | | | $ | 158 | | | $ | 88 | |
| | | |
| | | |
| | | |
| |
Upgrader throughput(1)(mbbls/day) | | | 65.4 | | | | 71.7 | | | | 70.0 | |
Synthetic crude oil sales(mbbls/day) | | | 59.3 | | | | 59.5 | | | | 60.6 | |
Upgrading differential($/bbl) | | $ | 10.81 | | | $ | 17.91 | | | $ | 13.77 | |
Unit operating cost(2)($/bbl) | | $ | 6.48 | | | $ | 7.35 | | | $ | 6.17 | |
| (1) | | Throughput includes diluent returned to the field. |
| |
| (2) | | Based on throughput. |
| | | | | | |
| Upgrading Earnings Variance Analysis ($ millions) |
| | | |
| Year ended December 31, 2000 | | $ | 88 | |
| | Volume | | | (8 | ) |
| | Differential | | | 115 | |
| | Operating costs — energy related | | | (29 | ) |
| | Operating costs — non-energy related | | | (5 | ) |
| | Other | | | 17 | |
| | DD&A | | | (1 | ) |
| | Income taxes | | | (19 | ) |
| | | |
| |
| Year ended December 31, 2001 | | | 158 | |
| | Volume | | | (1 | ) |
| | Differential | | | (181 | ) |
| | Operating costs — energy related | | | 39 | |
| | Operating costs — non-energy related | | | (1 | ) |
| | Other | | | (6 | ) |
| | DD&A | | | (1 | ) |
| | Income taxes | | | 47 | |
| | | |
| |
Year ended December 31, 2002 | | $ | 54 | |
| | | |
| |
Infrastructure and Marketing Earnings Summary
| | | | | | | | | | | | | | |
| Year ended December 31 ($ millions, except where indicated) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Gross margin | | | | | | | | | | | | | | | | |
| | Pipeline | | $ | 55 | | | $ | 86 | | | $ | 87 | |
| | Other infrastructure and marketing | | | 147 | | | | 111 | | | | 30 | |
| | | |
| | | |
| | | |
| |
| | | | 202 | | | | 197 | | | | 117 | |
| Other expenses | | | 10 | | | | 10 | | | | 1 | |
| DD&A | | | 20 | | | | 17 | | | | 15 | |
| Income taxes | | | 65 | | | | 72 | | | | 45 | |
| | | |
| | | |
| | | |
| |
| Earnings | | $ | 107 | | | $ | 98 | | | $ | 56 | |
| | | |
| | | |
| | | |
| |
Aggregate pipeline throughput(mbbls/day) | | | 457 | | | | 537 | | | | 528 | |
| | | |
| | | |
| | | |
| |
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2002 compared with 2001
Total midstream earnings decreased by $95 million (37 percent) to $161 million in 2002 from $256 million in 2001 due to:
| | • | | upgrading differential narrowing to average $10.81/bbl in 2002 versus $17.91/bbl in 2001 |
partially offset by:
| | • | | lower energy related operating costs |
Lower throughput in 2002 compared with 2001 was due to a plant turnaround in June and subsequent operational problems. However synthetic crude oil sales in 2002 were augmented by sales of third party product.
Infrastructure and marketing operations earnings increased nine percent in 2002 due to:
| | • | | improved crude oil and natural gas commodity margins |
| |
| | • | | higher cogeneration income |
partially offset by:
| | • | | reduced heavy crude pipeline throughput |
Lower income taxes in 2002 compared with 2001 related to lower pre-tax earnings and rate reductions in British Columbia and Alberta and federal rate reductions for non-resource income.
![[Bar Graph - Upgrader Throughput]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935713.gif)
![[Bar Graph - Pipeline Throughput]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935714.gif)
Midstream Capital Expenditures
Midstream capital expenditures in 2002 were primarily for upgrader, pipeline and cogeneration plant upgrades and upgrader debottlenecking front-end engineering.
| | | | | | | | | | | | | |
| Year ended December 31 ($ millions) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Upgrader | | $ | 41 | | | $ | 47 | | | $ | 12 | |
| Infrastructure and marketing | | | 17 | | | | 58 | | | | 47 | |
| | | |
| | | |
| | | |
| |
| | | $ | 58 | | | $ | 105 | | | $ | 59 | |
| | | |
| | | |
| | | |
| |
Page 17
Results of Operations
Refined Products
Refined Products Earnings Summary
| | | | | | | | | | | | | | |
| Year ended December 31 ($ millions, except where indicated) | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Gross margin | | | | | | | | | | | | |
| | Fuel sales | | $ | 81 | | | $ | 69 | | | $ | 55 | |
| | Ancillary sales | | | 26 | | | | 27 | | | | 26 | |
| | Asphalt sales | | | 45 | | | | 106 | | | | 38 | |
| | | |
| | | |
| | | |
| |
| | | | 152 | | | | 202 | | | | 119 | |
| Operating and other expenses | | | 64 | | | | 59 | | | | 60 | |
| DD&A | | | 34 | | | | 31 | | | | 28 | |
| Income taxes | | | 22 | | | | 49 | | | | 15 | |
| | | |
| | | |
| | | |
| |
| Earnings | | $ | 32 | | | $ | 63 | | | $ | 16 | |
| | | |
| | | |
| | | |
| |
| Number of fuel outlets | | | 571 | | | | 580 | | | | 579 | |
| Refined product sales volume | | | | | | | | | | | | |
| | Light oil products(million litres/day) | | | 7.7 | | | | 7.6 | | | | 7.4 | |
| | Asphalt products(mbbls/day) | | | 20.8 | | | | 21.4 | | | | 20.2 | |
| Refinery throughput | | | | | | | | | | | | |
| | Lloydminster refinery(mbbls/day) | | | 22.0 | | | | 23.7 | | | | 23.4 | |
| | Prince George refinery(mbbls/day) | | | 10.1 | | | | 10.2 | | | | 9.2 | |
2002 compared with 2001
Total refined products earnings decreased by $31 million (49 percent) to $32 million in 2002 from $63 million in 2001. Earnings from asphalt product operations were lower in 2002 due to higher heavy crude oil feedstock costs. Light oil refined product earnings increased primarily due to improved fuel margins.
![[Bar Graph - Light Oil Products]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935715.gif)
![[Bar Graph - Prince George Refinery]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935716.gif)
![[Bar Graph - Asphalt Products]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935717.gif)
![[Bar Graph - Lloydminster Refinery]](https://capedge.com/proxy/40-F/0001130319-03-000284/o09357o0935718.gif)
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Refined Products Capital Expenditures
In 2002, capital expenditures of $28 million were directed toward marketing outlet improvements, the remainder was spent on refinery maintenance.
Results of Operations
Corporate
Interest
Interest expense less interest income and capitalized interest was $104 million in 2002 compared with $101 million in 2001. Interest capitalized in 2002 was $26 million compared with $51 million in 2001 reflecting the completion of the Terra Nova development project and the resultant cessation of interest being capitalized to the project. Interest continued to be capitalized to the White Rose development project in 2002. Interest income was $1 million in both 2002 and 2001. Total interest paid on short- and long-term debt in 2002 was $131 million compared with $153 million in 2001 reflecting lower interest rates in 2002. Husky’s effective interest rate for 2002 after the effect of swaps was 5.48 percent compared with 6.86 percent during 2001.
Foreign Exchange
Foreign exchange losses during 2002 comprised $13 million of cash losses and $11 million of non-cash realized losses on long-term debt offset by $11 million of unrealized gains on long-term debt. Foreign exchange cash losses were related to other monetary items, primarily foreign exchange collars.
In June 2002, U.S. $400 million of 10-year debt securities were issued. The Canadian dollar equivalent on issue was $617 million based on an exchange rate of $1.5432. On December 31, 2002 the exchange rate was $1.5796 generating a loss of approximately $15 million, and offsetting gains on other U.S. dollar denominated debt.
Effective January 1, 2002, due to a change in Canadian generally accepted accounting principles, foreign exchange gains and losses on long-term monetary items are no longer deferred and amortized but, as is the practice in the United States, are reflected in earnings in the period they occur. Results from prior periods have been restated to reflect this change. The U.S./Canadian exchange rates expressed in Canadian dollars at December 31, 2002, 2001, 2000 and 1999 were $1.5796, $1.5926, $1.5002 and $1.4433, respectively.
Income Taxes
Income tax expense in 2002 amounted to $420 million, substantially unchanged from 2001. Income tax in 2002 reflected the effect of the British Columbia and Alberta corporate income tax rate reductions and a reduction of the federal corporate income tax rate for non-resource income. Current taxes in 2002 comprised $41 million on Wenchang earnings, $18 million of capital tax and the remainder for other taxes.
At December 31, 2002 Husky’s tax pools consisted of the following:
| | | | | |
| ($ millions) | | |
| | | | |
| Canadian Development Expense | | $ | 960 | |
| Canadian Oil and Gas Property Expense | | | 942 | |
| Foreign Exploration and Development Expense | | | 247 | |
| Undepreciated Capital Costs | | | 1,515 | |
| Other | | | 36 | |
| | | |
| |
| | | $ | 3,700 | |
| | | |
| |
Corporate Capital Expenditures
Corporate capital expenditures amounted to $23 million in 2002 and $22 million in 2001 and were primarily for computer hardware and software and office furniture and equipment.
Sensitivity Analysis
The following table shows the effect on net earnings and cash flow of changes in certain key variables. The analysis is based on business conditions and production volumes during 2002. Each separate item in the sensitivity analysis assumes the others are held constant. While these sensitivities are applicable for the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or greater magnitudes of change.
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Sensitivity Analysis
| | | | | | | | | | | | | | | | | | | |
| Item | | Increase | | Effect on Pre-tax Cash Flow | | Effect on Net Earnings |
| |
| |
| |
|
| | | | | ($ millions) | | ($/share)(6) | | ($ millions) | | ($/share)(6) |
| WTI benchmark crude oil price(1) | | U.S. $1.00/bbl | | | 101 | | | | 0.24 | | | | 64 | | | | 0.15 | |
| NYMEX benchmark natural gas price(2) | | U.S. $0.20/mmbtu | | | 39 | | | | 0.09 | | | | 23 | | | | 0.05 | |
| Light/heavy crude oil differential(3) | | Cdn. $1.00/bbl | | | (28 | ) | | | (0.07 | ) | | | (17 | ) | | | (0.04 | ) |
| Light oil margins | | Cdn. $0.005/litre | | | 14 | | | | 0.03 | | | | 8 | | | | 0.02 | |
| Asphalt margins | | Cdn. $1.00/bbl | | | 8 | | | | 0.02 | | | | 5 | | | | 0.01 | |
| Exchange rate (U.S. $ per Cdn. $)(4) | | U.S. $0.01 | | | (41 | ) | | | (0.10 | ) | | | (26 | ) | | | (0.06 | ) |
| Interest rate(5) | | 1% | | | (12 | ) | | | (0.03 | ) | | | (8 | ) | | | (0.02 | ) |
| (1) | | Excludes the impact of hedging. Hedged oil volumes at December 31, 2002 were immaterial. |
| |
| (2) | | Includes decrease in earnings related to natural gas consumption. |
| |
| (3) | | Includes impact of upstream and upgrading operations only. |
| |
| (4) | | Assumes no foreign exchange gains or losses on U.S. $ denominated long-term debt and other monetary items. In 2002 a new accounting standard eliminates the deferral of foreign exchange gains and losses on long-term monetary items. The impact of the Canadian dollar strengthening by U.S. $0.01 would be an increase of $19 million in net earnings based on December 31, 2002 U.S. $ denominated debt levels. |
| |
| (5) | | Interest rate sensitivity based on annual weighted obligations. |
| |
| (6) | | Based on December 31, 2002 common shares outstanding of 417.9 million. |
Liquidity and Capital Resources
Financial Ratios
| | | | | | | | | | | | | | |
| Year ended December 31 | | 2002 | | 2001 | | 2000 |
| |
| |
| |
|
| Cash flow | — operating activities($ millions) | | $ | 1,892 | | | $ | 1,930 | | | $ | 1,209 | |
| | — financing activities($ millions) | | $ | 3 | | | $ | (423 | ) | | $ | (558 | ) |
| | — investing activities($ millions) | | $ | (1,589 | ) | | $ | (1,507 | ) | | $ | (651 | ) |
Debt to capital employed(percent) | | | 31.8 | | | | 32.8 | | | | 37.4 | |
| Debt to cash flow from operations | | | 1.1 | | | | 1.1 | | | | 1.7 | |
Corporate reinvestment ratio(1) | | | 0.8 | | | | 0.8 | | | | 0.6 | |
| (1) | | Capital and investment expenditures divided by cash flow from operations. |
In 2002 cash generated by operating activities was $1,892 million, a decrease of $38 million from the $1,930 million recorded in 2001 and an increase of $683 million from the $1,209 million in 2000. Lower cash from operating activities in 2002 was primarily due to higher accounts receivable and inventories. Cash used in investing activities amounted to $1,589 million in 2002, an increase of $82 million from the $1,507 million in 2001 and an increase of $938 million from the $651 million in 2000.
In 2002 cash provided from financing activities comprised $972 million from the issuance of long-term debt and $9 million of proceeds from the exercise of stock options. Cash utilized by financing activities in 2002 comprised $778 million for debt repayment, $151 million for dividends on common shares, $31 million for return on capital securities payment, $9 million for debt issue costs and a change of $9 million in non-cash working capital.
In 2001 financing activities utilized a net $423 million comprising debt repayments, net of issues, of $290 million, dividends of $150 million, return on capital securities payment of $30 million and reduction of site restoration provision of $4 million partially offset by a change of $42 million in non-cash working capital and proceeds of $9 million from the exercise of stock options.
In 2002 investing activities comprised $1,695 million for capital expenditures and acquisition costs partially offset by asset sales of $93 million and other adjustments of $13 million. In 2001 investing activities comprised $1,598 million of capital expenditures and acquisition costs partially offset by asset sales of $67 million and other adjustments of $24 million.
Page 20
Cash and cash equivalents at December 31, 2002 totalled $306 million compared with a nil balance at the beginning of the year. During January 2003, $200 million of the cash was utilized to settle the accounts under the Company’s receivable sales agreement outstanding at the end of the year. Total debt, net of cash and cash equivalents was $2,079 million at December 31, 2002.
Financing Activities
As at December 31, 2002 Husky’s outstanding long-term debt totalled $2,385 million, including amounts due within one year, compared with $2,092 million at December 31, 2001.
At December 31, 2002 there were no drawings under the Company’s $940 million revolving syndicated credit facility. Interest rates on this facility vary and are based on Canadian prime, Bankers’ Acceptance, U.S. LIBOR or U.S. base rate, depending on the borrowing option selected, credit ratings assigned by certain rating agencies to the Company’s senior unsecured debt and whether the facility is revolving or non-revolving.
At December 31, 2002 the Company had utilized in support of letters of credit $12 million of its $195 million in short-term credit facilities. The interest rates applicable to these facilities vary and are based on Canadian prime, Bankers’ Acceptance, money market rates or U.S. dollar equivalents.
Effective June 14, 2002, the Company issued U.S. $400 million of 6.25 percent notes under a U.S. $1 billion base shelf prospectus dated June 6, 2002. See note 9 of the Consolidated Financial Statements.
Effective January 23, 2003 the Company swapped the U.S. $150 million 6.875 percent notes due November 2003 to $229 million 8.5 percent debt due November 2003. This transaction effectively fixes the exchange rate on the U.S. notes at $1.525. As a result there will be no future foreign exchange gains or losses on these notes up to their maturity date.
The Company has an agreement to sell up to $200 million of net trade receivables on a continual basis. The agreement calls for purchase discounts, based on Canadian commercial paper rates, to be paid on an ongoing basis. The average effective rate in 2002 was approximately 2.8 percent (2001 — 4.7 percent). The Company has potential exposure to an immaterial amount of credit loss under this agreement. As at December 31, 2002 $200 million of net trade receivables had been sold.
The Company believes that, based on its current forecast for commodity prices for 2003, together with the corporate hedging plan its capital program of $1.8 billion will be funded by operating activities and, to the extent required, available lines of credit. In the event of significantly lower cash flow the Company is able to defer certain of its capital spending programs without penalty.
The Company declared dividends aggregating $0.36 per share ($151 million) in 2002. The board of directors of Husky has established a dividend policy that pays quarterly dividends of $0.09 ($0.36 annually) per common share. However, there can be no assurance that further dividends will be declared. The declaration of dividends will be at the discretion of the Board of Directors which will consider earnings, capital requirements, financial condition of the Company and other relevant factors.
At December 31, 2002 Husky had the following credit ratings:
| | | | | | | | | |
| | | Rating | | Debt Rated |
| | |
| |
|
| Standard and Poor’s Rating Service | | BBB | | Senior unsecured debt |
| | | BB+ | | Capital securities |
| | | BBB | | 8.45% senior secured bonds |
| Moody’s Investor Service | | Baa2 | | Senior unsecured debt |
| | | Ba1 | | Capital securities |
| | | Baa2 | | 8.45% senior secured bonds |
| Dominion Bond Rating Service | | BBB (high) | | Senior unsecured long-term notes |
| | | BBB | | Capital securities |
SIGNIFICANT ACCOUNTING POLICIES
The preparation of financial statements in accordance with generally accepted accounting principles requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. The following is included in Management’s Discussion and Analysis to aid the reader in assessing the critical accounting policies and practices of the Company and the likelihood of materially different results being reported depending on management’s assumptions and changes in prevailing conditions which
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affect the application of these policies and practices. Significant accounting policies are disclosed in note 3 of the Consolidated Financial Statements. Inherent in the application of a number of these policies is the requirement of management to make certain assumptions and interpretations that affect the determination of assets, liabilities, revenues and expenses. Accordingly, the emergence of new information and changed circumstances can cause material changes in reported financial results.
The following assessment of significant accounting policies is not meant to be exhaustive. Materially different results might occur from the application of the entire series of accounting policies to which the Company might be subject. Additionally, the Company might realize different results from the application of new accounting standards promulgated by various rule-making bodies.
Proved Oil and Gas Reserves
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas liquids including condensate and natural gas that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if they can be produced economically as demonstrated by either actual production or conclusive formation tests. Reserves which must be produced through the application of enhanced recovery techniques are included in the proved category only after successful testing by a pilot project or operation of an installed program in the same reservoir that provides support for the engineering analysis on which the project was based. Proved developed reserves are expected to be produced through existing wells and with existing facilities and operating methods.
The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the Company’s plans. The effect of changes in proved oil and gas reserves on the financial results and position of the Company is described under the heading “Full Cost Accounting for Oil and Gas Activities”.
Full Cost Accounting for Oil and Gas Activities
Depletion Expense
The Company uses the Full Cost Method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether successful or not. The aggregate of net capitalized costs, estimated future development costs and estimated removal and site restoration costs is amortized using the unit of production method based on estimated proved oil and gas reserves.
An increase in estimated proved oil and gas reserves will result in a corresponding reduction in depletion expense. A decrease in estimated future development costs will result in a corresponding reduction in depletion expense.
Withheld Costs
Certain costs related to unproved properties and major development projects may be excluded from costs subject to depletion until proved reserves have been determined or their value is impaired. These properties are reviewed quarterly and any impairment is transferred to the costs being depleted or, if the properties are located in a cost centre where there is no reserve base, the impairment is charged directly to earnings.
Ceiling Test
The Full Cost Method of accounting requires the calculation of a ceiling test which limits the net capital costs carried to an amount that is equal to or less than the estimated future net cash inflows from the Company’s oil and gas properties, including net cost less impairment of unproved properties. The test is a cost recovery test and is not intended to represent an estimate of fair market value. The test is performed quarterly. If the net carrying cost of the oil and gas properties exceeds the indicated limit then the difference is charged to earnings.
Impairment of Long-lived Assets
In addition to testing the permitted limits of oil and gas asset carrying costs, the Company is required to review the carrying value of all other property, plant and equipment for potential impairment. The review for impairment compares the carrying cost to the estimated fair value of the long-lived asset and if the carrying cost exceeds the fair value the difference is charged to earnings.
Asset Retirement Obligations
The Company is required to provide for future removal and site restoration costs, net of expected recoveries. The Company must estimate these costs in accordance with existing laws, contracts or other policies and
Page 22
must estimate the expected recoveries, which is generally the salvage value or residual value of an asset. These estimated net costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are charged to earnings when management is able to determine the amount and the likelihood of the future obligation.
Legal, Environmental Remediation and Other Contingent Matters
The Company is required to both determine whether a loss is probable based on judgement and interpretation of laws and regulations and determine that the loss can reasonably be estimated. When the loss is determined it is charged to earnings. The Company’s management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance.
Income Tax Accounting
The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, actual income tax liability may differ significantly from that estimated and recorded by management.
New Accounting Standards
In June 2001 the Financial Accounting Standards Board issued Statement No. 143 “Accounting for Asset Retirement Obligations”. Financial Accounting Statement (“FAS”) 143 requires an entity to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When initially recorded, the liability is added to the related property, plant and equipment, subsequently increasing depletion, depreciation and amortization expense. In addition, the liability is accreted for the change in present value in each period. Upon adoption of FAS 143 the Company will adjust its existing future removal and site restoration liability using the cumulative-effect approach. FAS 143 is effective for fiscal years commencing on or after January 1, 2003. The Canadian Institute of Chartered Accountants issued an exposure draft entitled “Asset Retirement Obligations” in April 2002 that is substantially the same as FAS 143 and is effective for fiscal years beginning on or after January 1, 2004.
The Company has estimated that the cumulative effect will be an increase of the future removal and site restoration liability of $58 million, an increase of related net property, plant and equipment of $56 million, a decrease to the future income tax liability of $1 million and a decrease in retained earnings of $1 million.
RESULTS OF OPERATIONS FOR 2001 COMPARED WITH 2000
Upstream
The increase in upstream revenues for 2001 was due to:
| | • | | higher production of crude oil and natural gas from the acquisition of Renaissance |
| |
| | • | | heavy oil exploitation programs in the Lloydminster heavy oil area |
| |
| | • | | higher realized natural gas prices |
partially offset by:
| | • | | lower crude oil and NGL prices |
Operating costs per unit of production increased 13 percent in 2001 as a result of:
| | • | | increased production of heavier gravity crude oil |
| |
| | • | | the operation of mature properties under waterflood and a higher proportion of low pressure shallow natural gas |
Total DD&A per boe was $7.31 in 2001 compared with $6.28 in 2000. The increase in the DD&A rate was primarily due to a full year of operations for the Renaissance properties.
Midstream
Higher earnings in 2001 was primarily due to wider upgrading differentials and improved crude oil and natural gas commodity marketing volumes and margins partially offset by higher energy related operating costs.
Page 23
Refined Products
Asphalt product operations accounted for most of the improved earnings in 2001 due to the lower cost feedstock and increased sales volume.
Corporate
Capitalized interest was primarily in respect of Terra Nova and White Rose projects. Interest paid in 2000 included $9 million in respect of the partial redemption of the Husky Terra Nova 8.45 percent senior secured bonds. Husky’s average interest rate in 2001 was approximately 6.9 percent compared with 7.5 percent in 2000.
QUARTERLY FINANCIAL SUMMARY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2002 | | 2001 |
| | | |
| |
|
| ($ millions, except where indicated) | | Q4 | | Q3 | | Q2 | | Q1 | | Q4 | | Q3 | | Q2 | | Q1 |
| |
| |
| |
| |
| |
| |
| |
| |
|
| Sales and operating revenues, net of royalties | | $ | 1,697 | | | $ | 1,669 | | | $ | 1,659 | | | $ | 1,359 | | | $ | 1,615 | | | $ | 1,470 | | | $ | 1,731 | | | $ | 1,780 | |
| Net earnings | | $ | 242 | | | $ | 173 | | | $ | 263 | | | $ | 126 | | | $ | 45 | | | $ | 118 | | | $ | 299 | | | $ | 192 | |
| Net earnings per share | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | — Basic | | $ | 0.57 | | | $ | 0.38 | | | $ | 0.64 | | | $ | 0.29 | | | $ | 0.09 | | | $ | 0.25 | | | $ | 0.74 | | | $ | 0.42 | |
| | — Diluted | | $ | 0.57 | | | $ | 0.38 | | | $ | 0.64 | | | $ | 0.29 | | | $ | 0.09 | | | $ | 0.24 | | | $ | 0.73 | | | $ | 0.42 | |
| Cash flow from operations | | $ | 635 | | | $ | 590 | | | $ | 498 | | | $ | 373 | | | $ | 287 | | | $ | 478 | | | $ | 561 | | | $ | 620 | |
| Cash flow from operations per share | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | — Basic | | $ | 1.50 | | | $ | 1.39 | | | $ | 1.18 | | | $ | 0.88 | | | $ | 0.67 | | | $ | 1.13 | | | $ | 1.33 | | | $ | 1.47 | |
| | — Diluted | | $ | 1.50 | | | $ | 1.39 | | | $ | 1.17 | | | $ | 0.87 | | | $ | 0.66 | | | $ | 1.12 | | | $ | 1.32 | | | $ | 1.46 | |
| Share price | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | — High | | $ | 17.20 | | | $ | 17.00 | | | $ | 17.98 | | | $ | 17.80 | | | $ | 20.25 | | | $ | 20.95 | | | $ | 17.30 | | | $ | 15.80 | |
| | — Low | | $ | 15.43 | | | $ | 14.00 | | | $ | 15.85 | | | $ | 14.20 | | | $ | 15.06 | | | $ | 14.65 | | | $ | 13.10 | | | $ | 13.20 | |
| | — Close (end of period) | | $ | 16.47 | | | $ | 16.70 | | | $ | 16.66 | | | $ | 17.10 | | | $ | 16.47 | | | $ | 17.85 | | | $ | 16.22 | | | $ | 13.25 | |
Shares traded(thousands) | | | 20,478 | | | | 30,620 | | | | 31,159 | | | | 34,383 | | | | 59,251 | | | | 46,993 | | | | 25,333 | | | | 25,280 | |
Number of weighted average common shares outstanding(thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | — Basic | | | 417,748 | | | | 417,497 | | | | 417,393 | | | | 416,939 | | | | 416,545 | | | | 416,025 | | | | 415,878 | | | | 415,805 | |
| | — Diluted | | | 419,567 | | | | 419,136 | | | | 419,558 | | | | 418,951 | | | | 419,367 | | | | 419,153 | | | | 418,337 | | | | 417,555 | |
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