10-K/A 1 form10ka1_2005.txt AMENDMENT NO. 1 ============================================================================== UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K/A AMENDMENT NO.1 ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2005 COMMISSION FILE NUMBER 1-6702 NEXEN INC. Incorporated under the Laws of Canada 98-6000202 (I.R.S. Employer Identification No.) 801 - 7th Avenue S.W. Calgary, Alberta, Canada T2P 3P7 Telephone - (403) 699-4000 Web site - www.nexeninc.com SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT: TITLE EXCHANGE REGISTERED ON ----- ---------------------- Common shares, no par value The New York Stock Exchange The Toronto Stock Exchange Subordinated Securities, due 2043 The New York Stock Exchange The Toronto Stock Exchange SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [_] On June 30, 2005, the aggregate market value of the voting shares held by non-affiliates of the registrant was approximately Cdn $9.7 billion based on the Toronto Stock Exchange closing price on that date. On January 31, 2006, there were 261,614,723 common shares issued and outstanding. =============================================================================== EXPLANATORY NOTE This Amendment No. 1 on Form 10-K/A (this "Amendment") amends the Annual Report on Form 10-K for the year ended December 31, 2005 filed on February 23, 2006 (the "Original Filing"). Nexen, Inc. (the "Company") has filed this Amendment to incorporate textual changes in Items 1 and 2, Business and Properties, in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in Item 7A, Quantitative and Qualitative Disclosures about Market Risk regarding our reserves process and risk factors. We made a textual change in Item 8, Financial Statements and Supplementary Data (Note 21- Differences Between Canadian and U.S. Generally Accepted Accounting Principles, page 110) regarding our modification of the tandem option plan. This Amendment has no effect on the Consolidated Balance Sheets, Consolidated Statements of Income, Consolidated Statement of Cash Flows, and Consolidated Statements of Changes in Shareholders' Equity, and more specifically, does not affect net income, earnings per share, total cash flows, current assets, total assets, current liabilities, total shareholders' equity or other information as presented in the Original Filing. Other information contained herein has not been updated. Therefore, this Amendment should be read together with other documents that the Company has filed with the Securities and Exchange Commission subsequent to the filing of the Original Filing. Information in such reports and documents updates and supersedes certain information contained in this Amendment. The filing of this Amendment shall not be deemed an admission that the Original Filing, when made, included any known, untrue statement of material fact or knowingly omitted to state a material fact necessary to make a statement not misleading. 1 TABLE OF CONTENTS PART I PAGE Items 1 and 2. Business and Properties 3 PART II Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation 24 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 64 Item 8 Financial Statements and Supplementary Data. 70 Special Note to Canadian Investors - see page 69 Unless we indicate otherwise, all dollar amounts ($) are in Canadian dollars, and oil and gas volumes, reserves and related performance measures are presented on a working interest before-royalties basis. Where appropriate, information on an after-royalties basis is provided in tabular format. Volumes and reserves include Syncrude operations unless otherwise stated. Below is a list of terms specific to the oil and gas industry. They are used throughout the Form 10-K. /d = per day mboe = thousand barrels of oil equivalent bbl = barrel mmboe = million barrels of oil equivalent mbbls = thousand barrels mcf = thousand cubic feet mmbbls = million barrels mmcf = million cubic feet mmbtu = million British thermal units bcf = billion cubic feet km = kilometre WTI = West Texas Intermediate MW = megawatt NGL = natural gas liquid In this 10-K, we refer to oil and gas in common units called barrel of oil equivalent (boe). A boe is derived by converting six thousand cubic feet of gas to one barrel of oil (6mcf/1bbl). This conversion may be misleading, particularly if used in isolation, as the 6mcf/1bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head. The noon-day Canadian to US dollar exchange rates for Cdn $1.00, as reported by the Bank of Canada, were: (US$) DECEMBER 31 AVERAGE HIGH LOW -------------------------------------------------------------------------------- 2001 0.6279 0.6458 0.6695 0.6241 2002 0.6331 0.6369 0.6618 0.6199 2003 0.7738 0.7135 0.7738 0.6350 2004 0.8308 0.7683 0.8493 0.7159 2005 0.8577 0.8253 0.8690 0.7872 On January 31, 2006, the noon-day exchange rate was US$0.8742 for Cdn $1.00. Electronic copies of our filings with the Securities Exchange Commission (SEC) and the Ontario Securities Commission (OSC) (from November 8, 2002 onward) are available, free of charge, on our website (www.nexeninc.com). Filings prior to November 8, 2002 are available free of charge, upon request, by contacting our investor relations department at (403) 699-5931. As soon as reasonably practicable, our filings are made available on our website once they are electronically filed with the SEC or the OSC. Alternatively, the SEC and the OSC each maintain a website (www.sec.gov and www.sedar.com) that contain our reports, proxy and information statements and other published information that have been filed or furnished with the SEC and the OSC. 2 PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES Page About Us ....................................................................4 Strategy ....................................................................5 Understanding the Oil and Gas Business ......................................5 Oil and Gas Operations North Sea--United Kingdom ...............................................6 Gulf of Mexico--United States ...........................................7 Canada ..................................................................9 Athabasca Oil Sands .....................................................9 Middle East--Yemen .....................................................12 Offshore West Africa ...................................................13 Other International ....................................................14 Reserves, Production and Related Information ...............................14 Syncrude Mining Operations .................................................18 Oil and Gas Marketing ......................................................20 Chemicals ..................................................................22 Additional Factors Affecting Business Government Regulations .................................................23 Environmental Regulations ..............................................23 Employees ..................................................................23 3 ABOUT US Nexen Inc. (Nexen, we or our) is an independent, Canadian-based, global energy company. We were formed in Canada in 1971 by the combination of the Canadian crude oil, natural gas, sulphur and chemical operations of two subsidiaries of Occidental Petroleum Corporation (Occidental). We've grown from producing 10,700 boe/d before royalties with revenues of $26 million in 1971, to 241,700 boe/d before royalties (including Syncrude production) and revenues of $4.1 billion in 2005. We achieved this growth through exploration success and strategic acquisitions. In more than 30 years of operations, we have been profitable every year, except one, and have been paying quarterly dividends consecutively since 1975. In the 1970s, we expanded our Western Canadian assets and entered the US Gulf of Mexico. We finished this decade with production of approximately 11,000 boe/d before royalties and revenues of $126 million. In the 1980s, we continued to expand in Western Canada by acquiring Canada-Cities Service, Ltd. in 1983. This acquisition doubled our size and included an interest in the Syncrude Joint Venture, our entry into the Athabasca oil sands. Acquisitions of Cities Offshore Production Co. in 1984 and Moore McCormack Energy, Inc. in 1988 further increased our presence in the Gulf of Mexico. We finished this decade with production of approximately 68,600 boe/d before royalties and revenues of $591 million. In the 1990s, we had two defining moments: discovering oil on the Masila block in Yemen and acquiring Wascana Energy Inc. The first of 17 fields at Masila was discovered in 1991, and Masila has produced more than 890 million barrels since start-up. Our 1997 purchase of Wascana Energy Inc. almost tripled our Canadian production. In 1998, we entered Australia with an interest in the offshore Buffalo field and Nigeria as the operator of the Ejulebe field. Also in 1998, we discovered Ukot on Block OPL-222, offshore Nigeria, the first of several discoveries to date on the block. We finished this decade with production of approximately 239,200 boe/d before royalties and revenues of $1.7 billion. So far in the 21st century, we have made a number of discoveries, two strategic acquisitions and completed a non-core divestiture program. In 2000, we discovered Gunnison in the deep-water Gulf of Mexico and Guando in Colombia. That same year, we joined with Ontario Teachers' Pension Plan Board (Teachers) to acquire Occidental's remaining 29% interest in us. Teachers purchased 20.2 million common shares. We repurchased the remaining 20 million common shares for $605 million, which would have had a value of more than $2.2 billion at year-end 2005. We also exchanged our oil and gas operations in Ecuador for Occidental's 15% interest in our chemical operations and we changed our name to Nexen Inc. from Canadian Occidental Petroleum Ltd. In 2001, we discovered Aspen in the deep-water Gulf of Mexico and signed a joint venture agreement with OPTI Canada Inc. to develop, produce and upgrade bitumen at Long Lake in the Athabasca oil sands. In 2002, we discovered Usan, the second discovery on OPL-222, offshore Nigeria. In late 2003, we discovered two fields on Block 51 in Yemen. And in 2004, we acquired properties in the UK North Sea, providing us with strategic operatorship of the Buzzard discovery, the producing Scott and Telford fields and 700,000 acres of exploratory acreage. In the third quarter of 2005, we sold Canadian conventional oil and gas properties producing approximately 18,300 boe/d before royalties. We also monetized 39% of our chemical business through the initial public offering of the Canexus Income Fund. During the year, we made a potentially significant discovery in the Gulf of Mexico at Knotty Head and commenced commercial development of our first coal bed methane (CBM) project in the Fort Assiniboine area in Western Canada. Now in 2006, we are on track to complete major development projects at Buzzard in the North Sea and the Syncrude Stage 3 expansion, followed by Long Lake in the Athabasca oil sands in 2007. These projects and an active exploration program provide future growth for our company. For financial reporting purposes, we report on four main segments: o oil and gas; o Syncrude; o oil and gas marketing; and o chemicals. Our oil and gas operations are broken down geographically into the UK North Sea, US Gulf of Mexico, Canada, Yemen and Other International (Colombia and offshore West Africa). Results from our Long Lake project are included in Canada. Syncrude is our 7.23% interest in the Syncrude Joint Venture. Marketing includes our growing crude oil, natural gas, natural gas liquids and power marketing business in North America and southeast Asia. Chemicals includes operations in North America and Brazil that manufacture, market and distribute sodium chlorate, caustic soda and chlorine. Production, revenues, net income, capital expenditures and identifiable assets for these segments appear in Note 20 to the Consolidated Financial Statements and in Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this report. 4 STRATEGY Our goal is to grow long-term value for shareholders. We define value growth as increasing reserves, production and cash flow over the long term. We believe in developing targeted capabilities, which generate opportunities and operations required for long-term success in our ever-evolving industry. As conventional basins in North America mature, we have developed specific capabilities in oil sands, coal bed methane, deep-water technology and international locations. These enable us to focus on specific types of projects, as we transition toward major projects in established basins, exploration in newer basins and exploitation of unconventional resources. Today, we are building new sustainable businesses in Western Canada, the North Sea, Gulf of Mexico, Middle East and offshore West Africa, capitalizing on the following corporate strengths: o We are successful deep-water explorers with significant discoveries at Knotty Head in the Gulf of Mexico and at Usan, offshore Nigeria; o We are skilled project managers with major development projects at Buzzard in the North Sea, and Long Lake in Canada's Athabasca oil sands. These projects are nearing completion on time and on budget; o We are innovative in our application of technology. Long Lake is expected to be the first oil sands project to use gasification technology to significantly reduce the cost of producing bitumen; o We are an international operator with a proven track record of successful business ventures in Yemen, Colombia and Australia; and o We make value-oriented acquisitions. In 2001, we purchased approximately 15% of our own shares, and in 2004, we made a strategic entry into the UK North Sea. The location and scale of our operations often result in an extended period of time from the capture of opportunities to first production and non-linear year-over-year growth in reserves and production. Significant up-front capital investment is often required prior to realizing production and free cash flows. We fund this investment by maximizing cash flow from our producing assets, issuing long-term debt and selling non-core assets into attractive markets. Our long-term strategy focuses on ensuring sufficient inventory of opportunities for future growth. Our major development project at Buzzard is expected to add significant production in late 2006, followed by Long Lake in 2007. With these projects on stream, we expect our net production in 2007 to grow by more than 50%, net of declines. Beyond 2007, we have a number of growth opportunities, including undeveloped discoveries at Knotty Head in the Gulf of Mexico and Usan and Ukot offshore Nigeria, together with future phases of our oil sands projects that we plan to develop sequentially. In creating sustainable businesses, we are committed to good corporate governance and social responsibility. We believe that over the long term, companies that follow sustainable business practices outperform those with narrower priorities. We foster dialogue with stakeholders about our operational opportunities and challenges, from exploration to production to reclamation. Our goal is to help stakeholders become engaged participants in a continuing consultation process, while balancing their multiple, and sometimes conflicting goals. UNDERSTANDING THE OIL AND GAS BUSINESS The oil and gas industry is highly competitive. With strong global demand for energy, there is intense competition to find and develop new sources of supply. Yet, barrels from different reservoirs around the world do not have equal value. Their value depends on the costs to find, develop and produce the oil or gas, the fiscal terms of the host regime and the price products command at market based on quality and marketing efforts. Our goal is to extract the maximum value from each barrel of oil equivalent, so every dollar of capital we invest generates an attractive return. Numerous factors can affect this. Changes in crude oil and natural gas prices can significantly affect our net income and cash generated from operating activities. Consequently, these prices may also affect the carrying value of our oil and gas properties and how much we invest in oil and gas exploration and development. We attempt to reduce the adverse impact of negative price changes by investing in projects that we believe will generate positive returns at relatively low commodity prices. We also have a broad customer base for our crude oil and natural gas. Alternative customers are generally available, and the loss of any one customer is not expected to have a significant adverse effect on the price of our products or our revenues. Oil and gas producing operations are generally not seasonal. However, demand for some of our products can have a seasonal component that can impact price. In particular, heavy oil is generally in higher demand in the summer for its use in road construction, and natural gas is generally in higher demand in the winter for heating. Our realized prices for our oil and gas products are mainly determined by volatile international crude oil markets and by North American gas markets and, as a result, we are price takers. 5 We manage our operations on a country-by-country basis, reflecting differences in the regulatory and competitive environments and risk factors associated with each country. OIL AND GAS OPERATIONS We have oil and gas operations in the UK North Sea, US Gulf of Mexico, Western Canada, Yemen, offshore West Africa and Colombia. We also have operations in Canada's Athabasca oil sands which produce synthetic crude oil. We operate most of our production and continue to develop new growth opportunities in each area by actively exploring and applying technology. In this Form 10-K/A, we provide estimates of remaining quantities of oil and gas reserves for our various properties. Such estimates are internally prepared. We had 96% of our oil and gas and Syncrude reserves before royalties (96% after royalties) assessed (either evaluated or audited as described on page 17) by independent reserves consultants. Their assessments are performed at varying levels of property aggregation, and we work with them to reconcile the differences on the portfolio of properties to within 10% in the aggregate. Estimates pertaining to individual properties within the portfolio often differ by significantly more than 10%, either positively or negatively; however, we believe such differences are not material relative to our total proved reserves. Refer to the section on Critical Accounting Estimates - Oil and Gas Accounting - Reserves Determination on page 59 for a description of our reserves process, and to the section on Reserves, Production and Related Information on page 17 for a description of the nature and scope of the independent assessments performed and the results thereof. NORTH SEA--UNITED KINGDOM (UK) The UK is one of our key growth areas. In 2004, we acquired a 43.2% operated interest in the Buzzard development, operated interests in the Scott and Telford producing fields, the Scott production platform, interests in several satellite discoveries and more than 700,000 net undeveloped exploration acres for US$2.1 billion. This acquisition established us as a significant regional player with concentrated assets, infrastructure and exploration and development potential for future growth. It added high-margin reserves and production, diversified our worldwide portfolio by adding strong assets in a stable jurisdiction, and complemented our other longer cycle-time projects. Our UK strategy is focused on exploration and exploitation opportunities near existing infrastructure. We have a number of exploitation opportunities in our existing fields and smaller satellite discoveries near infrastructure. Most of our unexplored acreage is near Scott/Telford or Buzzard where new discoveries could be tied-in quickly, upon success. At year end, the UK had proved reserves of 145 mmboe before royalties (145 mmboe after royalties) representing about 18% of Nexen's total proved oil and gas and Syncrude reserves. BUZZARD DEVELOPMENT Buzzard is one of the largest discoveries in the UK North Sea in recent years. Discovered in 2001, it is in the Outer Moray Firth, central North Sea, about 60 miles northeast of Aberdeen, in 317 feet of water. Development of Buzzard is on budget and on schedule with first production expected by late 2006. In 2005, we installed three platform jackets and the wellhead deck and tied-in the water injection, gas export and oil export pipelines. In October 2005, we began drilling production wells. Development of the facilities is approximately 88% complete. In summer 2006, we plan to install the utilities and production topsides and initiate hook-up and project commissioning. The facilities will have a capacity of 200,000 bbls/d of oil and 60 mmcf/d of gas. We anticipate the field will be produced through 27 production wells, of which eight will be pre-drilled and available to begin producing by late 2006. Reservoir pressure will be maintained through an active water-flood program. We estimate peak gross production rates at approximately 200,000 bbls/d of oil and approximately 30 mmcf/d of gas, with our share about 85,000 boe/d after royalties. Oil from Buzzard will be exported via the Forties pipeline to the Grangemouth refinery in Scotland. Gas will be exported via the Frigg system to the St. Fergus Gas Terminal in northeast Scotland. In 2006, we plan to invest approximately $450 million to complete the facilities and drill eight production and six water injection wells. UK PRODUCTION Scott and Telford are producing fields with additional exploitation opportunities. Scott, in which we have a 41% working interest, was discovered in 1987 and began producing in September 1993. We have a 54.3% working interest in Telford, which was discovered in 1991 and came on stream in 1996. In 2005, our share of Scott and Telford royalty-free production approximated 16,000 boe/d, of which 80% was oil. Oil and gas is produced through numerous subsea wells and from wells drilled from the Scott platform. Oil is delivered to the Grangemouth refinery in Scotland via the Forties pipeline, while gas is exported via the SAGE pipeline to the St. Fergus terminal in northeast Scotland. In 2005, the Scott platform underwent a significant maintenance turnaround and facilities upgrade to improve reliability and extend facility life. Upgrades included improvements to electric, produced water injection, and drilling and metering systems. In 2006, 6 we plan to invest approximately $35 million to drill, complete, and tie-in three development wells and perform workovers. Our 2004 UK acquisition included a non-operated interest in Farragon, a small satellite discovery, which was brought on stream in November 2005. At year end, our 20% share of royalty-free production from Farragon was 3,900 boe/d and is expected to average between 3,000 and 4,000 boe/d in 2006. EXPLORATION AND UNDEVELOPED ASSETS In 2005, we drilled and found hydrocarbons at Polecat, Yeoman and Black Horse. Although the hydrocarbons discovered at Polecat and Black Horse are insufficient to warrant stand alone development, these wells may form part of a future larger development plan for the area. We have a number of smaller discoveries on operated blocks near Scott, Buzzard and third-party facilities as follows:
------------------------------------------------------------------------------------------------------------------ Field Interest (%) Operator Status Comments ------------------------------------------------------------------------------------------------------------------ Ettrick 80 operated sanctioned in February 2006 for development ------------------------------------------------------------------------------------------------------------------ Bugle 82 operated discovery near Scott; evaluating development alternatives ------------------------------------------------------------------------------------------------------------------ Duart 50 non-operated discovery near Scott; evaluating development alternatives ------------------------------------------------------------------------------------------------------------------ Dolphin 42 operated discovery near Scott; evaluating development alternatives ------------------------------------------------------------------------------------------------------------------ Perth 42 operated discovery near Scott; evaluating development alternatives ------------------------------------------------------------------------------------------------------------------ Selkirk 38 operated evaluating development alternatives ------------------------------------------------------------------------------------------------------------------ Yeoman 50 operated discovery near Scott; evaluating development alternatives ------------------------------------------------------------------------------------------------------------------
We recently announced our plans to develop the Ettrick field, which includes drilling three production wells tied back to a floating production, storage and offloading vessel. The field is expected to begin production in early 2008, with our share reaching approximately 16,000 boe/d. Our share of full-cycle development costs are estimated at $460 million with approximately $90 million invested in 2006. The other discoveries are in various stages of evaluation. During 2005, we drilled the Saracen and Bennachie exploration wells, which encountered noncommercial hydrocarbons and were abandoned. We also increased our land acreage by approximately 388,000 acres to support our future exploration activity. We expect to drill four exploration wells in 2006. The offshore drilling rig market is currently tight, however, we have secured drilling rigs for most of our 2006 North Sea exploration and development program. FISCAL TERMS UK fiscal terms are favourable. New discoveries pay no royalties and result in cash netbacks that are higher than our company average. Scott is subject to Petroleum Revenue Tax (PRT), although no PRT is payable until available oil allowances have been fully utilized, which isn't expected before 2009. Once payable, PRT is levied at 50% of cash flow after capital expenditures, operating costs and an oil allowance. PRT is applicable to fields receiving development consent prior to March 1993. Buzzard, Telford and Farragon fields are not subject to PRT. PRT is deductible for corporate income tax purposes. The UK corporate income tax rate is 30% of taxable income. Income from oil and gas activities is also subject to a supplemental charge of 10%, although in a recent pre-budget announcement, the UK government said it intends to increase this to 20%, effective January 1, 2006. This increase is subject to the introduction of legislation. The amount and timing of income taxes payable depends on many factors including price, production and capital investment levels. GULF OF MEXICO--UNITED STATES (US) The Gulf of Mexico is an integral part of our growth strategy. Large discoveries, high success rates, production infrastructure and attractive fiscal terms make the deep-water Gulf of Mexico one of the world's most prospective sources for oil and gas. The deep-water prospects generally have multiple sands and high production rates, factors which reduce risk and improve economics. Technology to find, drill, and develop discoveries is rapidly progressing and becoming more cost effective. The deep-water Gulf is relatively near infrastructure and continental US markets, enabling discoveries to be brought on stream in a reasonable period of time. Our strategy in the Gulf is to explore for new reserves, acquire assets with upside potential and exploit our existing asset base. We focus our exploration program on three strategic play types: o deep-shelf gas prospects; o deep-water prospects near existing infrastructure; and o deep-water, sub-salt plays with potential to become new core areas. 7 These plays are relatively under-explored, hold potential for large discoveries and have attractive fiscal terms. The shorter-cycle times for shelf gas and deep-water prospects near infrastructure complement the longer-cycle times for deep-water sub-salt plays. Although competition in the Gulf is strong, a lot of expiring acreage becoming available over the next few years may provide us access to additional exploration opportunities. In 2005, we invested $362 million on exploration and development activities in the Gulf. This resulted in a number of discoveries, including Knotty Head, a large, four-way dip closure in the Miocene sub-salt play. Knotty Head showcases the potential in the Gulf, as it has the potential to be a major discovery. In 2006, we plan to invest approximately $500 million in the Gulf to further our strategy.
US PRODUCTION ----------------------------------------------- -------------------------------- --------------------------------- 2005 2004 2003 ----------------------------------------------- -------------------------------- --------------------------------- Before After Before After Before After (mboe/d) Royalties Royalties Royalties Royalties Royalties Royalties ----------------------------------------------- -------------------------------- --------------------------------- Deep-water 24.0 21.5 32.1 28.7 24.0 21.7 ----------------------------------------------- -------------------------------- --------------------------------- Shallow-water 17.6 4.6 22.6 18.8 28.5 23.7 ----------------------------------------------- -------------------------------- --------------------------------- Total 41.6 36.1 54.7 47.5 52.5 45.4 ----------------------------------------------- -------------------------------- ---------------------------------
In 2005, we produced approximately 41,600 boe/d before royalties (36,100 after royalties), even after weather-related disruptions. This represents about 17% of Nexen's total production. Weather is a risk in the Gulf of Mexico: specifically tropical storms and hurricanes can damage facilities, drilling rigs and surrounding infrastructure, interrupt production, and delay exploration and development programs. In 2005, hurricanes reduced our production by approximately 6,000 boe/d before royalties. Although we received minor damage at two of our facilities, by year end we were producing at 92% of our full potential. We expect to be back to full production by mid 2006. We carry property and business interruption insurance to mitigate losses caused by adverse weather. At year end, we had proved reserves of 90 mmboe before royalties (77 mmboe after royalties) representing about 11% of Nexen's total proved oil and gas and Syncrude reserves. Our production and reserves in the Gulf are primarily concentrated in two deep-water and five shallow-water fields. We operate most of this production. DEEP-WATER PRODUCTION Our deep-water production comes from our 100%-operated Aspen field and 30% non-operated Gunnison field. Aspen is on Green Canyon Block 243 in 3,150 feet of water. The project was developed using sub-sea wells tied back to the Shell-operated Bullwinkle platform 16 miles away. Production began in December 2002, and we achieved payout on our full investment in Aspen in January 2005. Our share of 2005 production before royalties was approximately 14,300 boe/d (13,000 after royalties). Production declined during the year because of increased water cuts. In 2006, we plan to drill another development well to access potential stranded reserves. Gunnison is in 3,100 feet of water, and includes Garden Banks Blocks 667, 668 and 669. Gunnison began production in December 2003 through our truss SPAR platform that can handle 40,000 bbls/d of oil and 200 mmcf/d of gas. We achieved payout on Gunnison in December 2005, just two years after first production. In 2005, we tied in one development well, and our share of production before royalties was approximately 9,700 boe/d (8,500 after royalties). Our Gunnison SPAR production facility has excess capacity, leaving room for growth from exploration and processing of third-party volumes. In 2006, we plan to complete and tie-in our 15% non-operated 2004 Dawson Deep discovery to the Gunnison SPAR. SHALLOW-WATER PRODUCTION Our shelf producing assets are offshore Louisiana, primarily in five 100%-owned fields: Eugene Island 18, Eugene Island 255/257/258/259, Eugene Island 295, Vermilion 302/321, and Vermilion 76 (consisting of Blocks 65, 66 and 67). We continue to exploit these assets and look for other opportunities on the shelf. Most of our 2005 shelf activities focused on development drilling at Vermilion 76 and 321. 8 EXPLORATION AND UNDEVELOPED ASSETS In 2005, our exploration program produced strong results with a potentially significant discovery at Knotty Head and several other smaller discoveries. Our undeveloped discoveries include:
--------------------------------------------------------------------------------------------- Well Interest (%) Operator Status Comments --------------------------------------------------------------------------------------------- Anduin 50 operated appraisal drilling planned in 2006 --------------------------------------------------------------------------------------------- Big Bend 50 non-operated expected to complete the well in 2007 --------------------------------------------------------------------------------------------- Dawson Deep 15 non-operated expected to begin producing in 2006 --------------------------------------------------------------------------------------------- Knotty Head 25 operated appraisal drilling ongoing in 2006 --------------------------------------------------------------------------------------------- Wrigley 50 non-operated expected to begin producing in 2006 --------------------------------------------------------------------------------------------- Tobago 10 non-operated expected to begin producing in 2009 or 2010 ---------------------------------------------------------------------------------------------
During the year, we drilled dry holes at Castleton and Vrede and increased our deep-water undeveloped land position by 95 blocks to over 240 blocks. We expect this acreage and future exploration opportunities to position us well for continued growth. In 2006, we plan to tie-in our 2004 Wrigley discovery to a third-party facility and drill appraisal wells at Knotty Head and Anduin. We also plan to drill eight exploration wells (five in the deep water and three in the deep shelf). Wells currently drilling with results expected in the first half of 2006 include Pathfinder and the Knotty Head sidetrack. We have drilling rigs secured for the majority of our 2006 drilling program and are actively working with partners to find rigs for the remainder. We recently committed to a deep-water drilling contract, which provides us with access to a new-build fifth generation dynamically positioned semi-submersible drilling rig for two years over a three-and-a-half year period. We expect this new rig to be available in mid 2009. FISCAL TERMS Royalty rates on our US production average 17% for shallow-water volumes and 10% for deep-water volumes. The fiscal terms are attractive, as we qualify for royalty relief at our deep-water Aspen and Gunnison fields on the first 87.5 mmboe of production. However, we are subject to royalties at Gunnison if annual commodity prices are higher than threshold prices set by the US Department of the Interior's Minerals Management Service. In 2005, commodity prices exceeded these thresholds, and we were subject to a 12.5% royalty at Gunnison. Royalties on other Gulf and state-water properties range from 12.5% to 25%. US taxable income is subject to federal income tax of 35% and state taxes ranging from 0% to 8%. CANADA Our strategy in Canada is to bring our new growth developments into production while we maximize value from our established operations. In the third quarter of 2005, we disposed of approximately 18,300 boe/d of production, comprising approximately 60% oil and 40% gas, and realized proceeds of $900 million (after closing adjustments). The assets we retained have upside potential for continued conventional development and enhanced recovery with advancements in extraction technology. During the year, we produced 49,900 boe/d before royalties (39,400 after royalties), which was approximately 21% of Nexen's total production. At year end 2005, proved reserves of 117 mmboe before royalties (101 mmboe after royalties) were approximately 15% of our total proved oil and gas and Syncrude reserves. Our remaining Canadian conventional assets comprise heavy oil in east-central Alberta and west-central Saskatchewan, and natural gas near Calgary and in southern Alberta and Saskatchewan. We operate most of our producing properties and hold 1.1 million net acres of undeveloped land across Western Canada. These assets provide predictable production volumes and earnings while we advance the following initiatives for future growth: o Athabasca oil sands--to produce and upgrade bitumen into synthetic crude; o enhanced oil recovery (EOR)--to increase recovery in our heavy oil fields; and o coal bed methane (CBM)--to extract natural gas primarily from Upper Mannville coals. In 2005, we invested $1,054 million in Canada, $776 million in these growth initiatives. In 2006, we plan to invest approximately $1,170 million, $800 million in these initiatives. ATHABASCA OIL SANDS The Athabasca oil sands in northeast Alberta is a key growth area for Nexen. Our strategy is to economically develop our bitumen resource in phases to provide low-risk, stable, future growth. Our Long Lake project involves integrating bitumen production with field upgrading technology to produce a premium synthetic crude oil that significantly reduces our need to purchase natural gas. It also includes our 7.23% investment in the Syncrude oil sands mining operation. 9 LONG LAKE PROJECT In 2001, we formed a 50/50 joint venture with OPTI Canada Inc. (OPTI) to develop the Long Lake property using steam-assisted-gravity-drainage (SAGD) for bitumen production and field upgrading using the proprietary OrCrude(TM); process. OrCrude(TM) is a technology to which OPTI has the exclusive Canadian license. We acquired the exclusive right to use this technology, with OPTI, within approximately 100 miles of Long Lake, and the right to use the technology independently elsewhere in the world. We operate the Long Lake lease and are responsible for constructing, developing and operating the SAGD project. OPTI will design, construct and operate the upgrader. We share equally in all project production and operating and capital costs. SAGD AND UPGRADER INTEGRATION SAGD involves drilling two parallel horizontal wells, generally between 2,300 and 3,300 feet long, with about 16 feet of vertical separation. Steam is injected into the shallower well, where it heats the bitumen that then flows by gravity to the deeper producing well. The OrCrude(TM) technology, using distillation, solvent de-asphalting and thermal cracking, separates the produced bitumen into partially upgraded sour crude oil and liquid asphaltenes. By coupling the OrCrude(TM) process with commercially available hydrocracking and gasification technologies, sour crude is upgraded to light (39* API) premium synthetic sweet crude oil, and the asphaltenes are converted to a low-energy, synthetic fuel gas. This gas is available as a low-cost fuel source, and as a source for hydrogen required in the hydrocracker. The gas will also be burned in a co-generation plant to produce steam for the SAGD operations and for electricity to be used on-site and sold to the electric grid. The energy conversion efficiency for our Long Lake upgrader is about 90% compared to 75% for a typical bitumen-fed coker, which provides us with a 50% margin advantage. OUR STRATEGIC ADVANTAGE Our SAGD and upgrading integration enables us to overcome three main economic hurdles of SAGD bitumen production: 1) the high cost of natural gas; 2) the cost of diluent; and 3) the realized price of bitumen. With synthetic gas from the asphaltenes as a fuel source, we have little need to purchase additional natural gas. With the upgrading facilities on site, expensive diluent is not required to transport the bitumen to market. And, by upgrading the bitumen into a highly desirable refinery feedstock or diluent supply, the end product commands light-sweet crude oil premium pricing. PROJECT MILESTONES AND COSTS The Long Lake project is on time and on budget. It received regulatory approval in 2003 and Nexen Board approval in 2004. Field construction on the SAGD and upgrader facilities began in 2004. In 2005, we continued module and site construction and completed drilling 78 SAGD well-pairs. Detailed engineering and purchasing of major equipment is substantially complete, with pricing largely as expected. Module construction of the SAGD is 87% complete, and site construction is 43% complete. Module construction of the upgrader is 64% complete and site construction is 32% complete. Approximately 69% of the project's total costs are committed. The major remaining cost uncertainty relates to labour access and productivity. First steam injection is scheduled to begin in late 2006, with upgrader start-up scheduled in the second half of 2007. We expect peak gross synthetic crude oil production to reach about 60,000 bbls/d before royalties and be maintained over the project's life, estimated at 40 years, by periodically drilling additional SAGD well-pairs. Combined SAGD, cogeneration and upgrading operating costs are expected to average between $11/bbl and $13/bbl, substantially lower than coking upgrading. In 2005, we invested $743 million at Long Lake and expect to invest approximately $650 million in 2006. Total project costs are estimated at $3.8 billion ($1.9 billion our share), which includes $250 million ($125 million our share) to increase the capability of the steam generating facility to ensure adequate bitumen supply as we fully develop the reservoir. This expansion will enable us to operate at a steam oil ratio of up to 3.3. In optimizing the value from the project, we will also construct a facility to concentrate soot produced by the gasifier and thereby reduce disposal costs. This facility is expected to cost approximately $110 million ($55 million our share). We expect ongoing capital to average between $2/bbl and $4/bbl. The capital costs of producing and upgrading bitumen using this technology are comparable to those for surface mining and coking upgrading on a barrel-of-daily production basis. RESERVES RECOGNITION Under SEC rules and regulations, we are required to recognize bitumen reserves rather than the upgraded premium synthetic crude oil that we will produce and sell. The economic recoverability of bitumen reserves is sensitive to natural gas prices, diluent costs and light/heavy differentials, risks that our project has been designed to eliminate. At December 31, 2005 and 2004, these factors made bitumen production uneconomic and, therefore, we did not recognize any proved bitumen reserves. Under Canadian standards, we would be permitted to recognize 200 mmbbls of high-value proved synthetic reserves before royalties (198 mmbbls after royalties) for our Long Lake project. 10 FUTURE PHASES We have 214,000 net acres of bitumen-prone lands in the Athabasca region and plan to continue acquiring more. We plan to continue developing our bitumen lands in a phased manner using our integrated upgrading strategy. In 2005, we announced our plan to duplicate Long Lake by developing Phase 2. In 2006, we will invest approximately $100 million in additional drilling, seismic and engineering to develop our leases and advance regulatory applications for future phases. Phase 2 SAGD production is expected to be on stream by late 2010 with upgrader start-up by the second half of 2011, followed by additional phases every two years or so. Each subsequent phase will leverage the knowledge and experience gained from successfully developing Long Lake and be similar in size and design to Long Lake. By keeping the core team in place and repeating and improving on existing designs and implementation plans, we expect to gain efficiencies in engineering, modular fabrication and on-site construction. We also anticipate enhanced operating efficiencies as we can train and move people easily between the various plants. HEAVY OIL Approximately 54% of our Canadian production is heavy oil. Heavy oil is characterized by high specific gravity or weight and high viscosity or resistance to flow. Because of these features, heavy oil is more difficult and expensive to extract, transport and refine than other types of oil. Heavy oil also yields a lower price relative to light oil, as a smaller percentage of high-value petroleum products can be refined from heavy oil. Our heavy oil operations are in east-central Alberta and west-central Saskatchewan. To maximize heavy oil returns, it is important to manage finding, development and operating costs. Our large production base and existing infrastructure are advantageous to us in managing these costs. In 2006, we plan to continue exploiting our existing fields through drilling and optimizing operations. ENHANCED OIL RECOVERY Heavy oil reservoirs typically have lower recovery factors than conventional oil reservoirs, leaving substantial amounts of oil in the ground. This creates an opportunity to increase recovery factors by applying new technology. We are continuing to research various technologies to enhance our heavy oil recovery with ongoing pilot projects in west-central Saskatchewan. NATURAL GAS Approximately 46% of our Canadian production is natural gas produced primarily from shallow sweet reservoirs in southern Alberta and Saskatchewan and from deep sour gas reservoirs near Calgary. Shallow gas is natural gas produced from shallow sand formations yielding low-pressure sweet gas. In general, shallower gas targets are cheaper to drill and develop, but have relatively smaller reserves and lower productivity per well. Sour gas is natural gas that contains hydrogen sulfide. We have been producing sour natural gas from our Balzac field northeast of Calgary since 1961. This sour gas is processed through our operated Balzac plant. COAL BED METHANE CBM is commonly referred to as an unconventional form of natural gas because it is primarily stored through adsorption by coal in coal deposits rather than in the pore space of the rock like most conventional gas. The gas is released in response to a drop in reservoir pressure. If the coal deposit is water saturated, water generally needs to be extracted to reduce the pressure and allow gas production to occur. If the coal does not produce water and is "dry", gas will be produced from initial development. Water-producing CBM wells in the United States generally show increasing gas production rates for a period of approximately one to three years before gas rates begin to decline. Our CBM pilot at Corbett in the Fort Assiniboine area of central Alberta has established techniques to produce natural gas from water saturated Upper Mannville coals. These coals are generally deeper than the Horseshoe Canyon "dry coal" play which is also being commercially developed in Alberta. We established commerciality of CBM production from the Mannville coals in 2005 by applying horizontal well technology. Commercial production rates and reduced de-watering time has enabled us to confidently develop these coals. In 2005, we approved commercial CBM developments at Corbett, Doris and Thunder in the Fort Assiniboine area. At the end of 2005, we held more than 600 net sections of land in Alberta with CBM potential, some of which overlay existing conventional producing lands. We have also established positions in other prospective CBM areas of Alberta. In 2006, we plan to invest $150 million to develop 115 gross (53 net) sections using single and multi-leg horizontal wells. In addition to our development at Fort Assiniboine, we will continue to evaluate other Mannville and Horseshoe Canyon CBM prospects and pursue new CBM opportunities in 2006. In 2005, we invested approximately $83 million in CBM to commence commercial development at Corbett, Thunder and Doris and build and evaluate our CBM acreage position. 11 FISCAL TERMS In Canada, we pay royalties ranging from 15% to 40% on production from lands owned by the federal and provincial governments. Some provinces also impose taxes on production from lands where they do not own the mineral rights. The Saskatchewan government assesses a resource surcharge on gross Saskatchewan resource sales that are subject to crown royalties of 3.6% that is reduced to 2.0% for wells completed after October 1, 2002. Profits earned in Canada from resource properties are subject to federal and provincial income taxes. In 2003, legislation was introduced to reduce the federal corporate income tax rate on income from Canadian oil and gas activities from 28% to 21% by 2007. Canadian entities are also subject to capital taxes. For our oil sands projects, we will pay royalties based on bitumen production, which includes a 1% royalty on gross revenue until all costs have been recovered at which time the royalty reverts to 25% on net revenue. With the combination of low royalties, our operating cost advantage and a premium product, our oil sands financial returns are expected to be attractive. MIDDLE EAST--YEMEN Yemen has been our most significant international region since we first began production at Masila in 1993. We operate the country's largest oil project and have developed excellent relationships with the government and local communities. Our success and reputation in Yemen open doors elsewhere in the Middle East and around the world. Our strategy is to maximize the value from our existing blocks, while we continue to search for new fields in deeper horizons. We have two producing blocks: Masila (Block 14) and East Al Hajr (Block 51). In 2005, we produced 12,700 bbls/d of oil before royalties (60,600 after royalties), representing approximately 39% of 2005 cash flow. Proved reserves of 105 mmboe before royalties (59 mmboe after royalties) comprise approximately 13% of Nexen's total proved oil and gas and Syncrude reserves. MASILA BLOCK (BLOCK 14) We have a 52% working interest in and operate the Masila project. Our share of 2005 production was 87,100 bbls/d before royalties (43,200 after royalties). After more than 10 years of growth, our Masila fields have matured, but significant value still remains. As a result of the Production Sharing Agreement (PSA) terms that govern Masila production, we still expect to generate approximately 33% of the total project cash flow from the remaining proved reserves. The first successful Masila exploratory well was drilled at Sunah in 1990, with additional discoveries quickly following at Heijah and Camaal. Initial production began in July 1993, with the first lifting of oil in August 1993. Masila Blend oil averages 31* API at very low gas-oil ratios. Most of the oil is produced from the Upper Qishn formation, but we also produce from deeper formations including the Lower Qishn, Upper Saar, Saar, Madbi, Basal Sand and basement formations. Production is collected at our Central Processing Facility (CPF) where water is separated for reinjection and oil is pumped to the Ash Shihr export terminal and shipped to customers primarily in Asia. We are managing the pace of our drilling program to ensure we recover the remaining reserves in the most efficient, cost-effective manner. In 2006, we plan to invest approximately $95 million to drill approximately 30 wells and test deeper horizons where we have had recent success. The PSA governing Masila production was signed in 1987 between the Government of Yemen and the Masila joint venture partners (Partners), including Nexen. Under the PSA, we have the right to produce oil from Masila into 2011 and to negotiate a five-year extension. Production is divided into cost recovery oil and profit oil. Cost recovery oil provides for the recovery of all exploration, development, and operating costs that are funded by the Partners. Costs are recovered from a maximum of 40% of production each year, as follows: -------------------------------------------------------------------------------- Costs Recovery -------------------------------------------------------------------------------- Operating 100% in year incurred -------------------------------------------------------------------------------- Exploration 25% per year for 4 years -------------------------------------------------------------------------------- Development 16.7% per year for 6 years -------------------------------------------------------------------------------- The remaining production is profit oil that is shared between the Partners and the Government and is calculated on a sliding scale based on production. The Partners' share of profit oil ranges from 20% to 33%. The structure of the agreement moderates the impact on Partners' cash flows during periods of low prices, as we recover our costs first and then share any remaining profit oil with the Government. At current production, the Government is entitled to approximately 72% of the profit oil, which includes a component for Yemen income taxes payable by the Partners at a rate of 35%. In 2005, the Partners' share of Masila production, including recovery of past costs, was approximately 37%. 12 EAST AL HAJR BLOCK (BLOCK 51) We have an 87.5% working interest and operate Block 51. This block is governed by a PSA between the Government of Yemen and the Partners: The Yemen Company (TYCO) (12.5% carried working interest) and Nexen (87.5% working interest).Under the PSA, TYCO has no obligation to fund capital or operating expenditures. For purposes of accounting and recording of reserves, we have determined TYCO's 12.5% participating interest is a royalty interest, and that our effective interest is 100%. We recognize both the Government's share and TYCO's share of profit oil under the PSA as royalties and taxes consistent with our treatment of our Masila operations. The PSA expires in 2023, and we have the right to negotiate a five-year extension. Under the terms of the PSA, the Partners pay a royalty ranging from 3% to 10% to the Government depending on production volumes. The remaining production is divided into cost recovery oil and profit oil. Cost recovery oil provides for the recovery of all of the project's exploration, development and operating costs, funded solely by Nexen. Costs are recovered from a maximum of 50% of production each year after royalties, as follows: -------------------------------------------------------------------------------- Costs Recovery -------------------------------------------------------------------------------- Operating 100% in year incurred -------------------------------------------------------------------------------- Exploration balance 75% per year, declining -------------------------------------------------------------------------------- Development balance 75% per year, declining -------------------------------------------------------------------------------- The remaining production is profit oil that is shared between the Partners and the Government on a sliding scale based on production rates. The Partners' share of profit oil ranges from 20% to 30%. The Government's share of profit oil includes a component for Yemen income taxes payable by the Partners at a rate of 35%. In 2005, the Partners' share of Block 51 production, including recovery of past costs, was approximately 61%. The first successful exploratory well was drilled at BAK-A in 2003, with BAK-B discovered shortly after. Block 51 development began in 2004 and includes a CPF, gathering system and a 22-km tieback to our Masila export pipeline. Early production began in November 2004 with 2005 production of 25,600 bbls/d before royalties (17,400 bbls/d after royalties). In 2005, we drilled four exploration wells on the block that were abandoned. In 2006, we plan to invest approximately $100 million to drill 17 development wells and continue exploring with three exploration wells. OFFSHORE WEST AFRICA Offshore West Africa is a growing core area where we already have discoveries. It offers prolific reservoirs and multiple opportunities to invest in this oil-rich region. Our strategy here is to explore and develop our portfolio for medium- to long-term growth. In 2005, we invested $47 million of capital offshore West Africa and expect to invest approximately $55 million in 2006. NIGERIA BLOCK OPL-222 In 1998, we acquired a 20% non-operated interest in Block OPL-222, which includes 448,000 acres and is approximately 50 miles offshore in water depths ranging from 600 to 3,500 feet. The ongoing appraisal of the block indicates significant hydrocarbon accumulations based on the drilling results outlined below:
---------------------------------------------------------------------------------------------------------------------- Year Well Location Results ---------------------------------------------------------------------------------------------------------------------- 1998 Ukot-1 Ukot field discovery well encountered three oil-bearing intervals and flowed at restricted rate of 13,900 bbls/d from two intervals ---------------------------------------------------------------------------------------------------------------------- 2002 Usan-1 Usan field discovery well encountered several oil-bearing intervals and flowed at restricted rate of 5,000 bbls/d from one interval ---------------------------------------------------------------------------------------------------------------------- 2003 Usan-2 3 km west of discovery appraised up-dip portion of the fault block ---------------------------------------------------------------------------------------------------------------------- 2003 Usan-3 2 km northwest of discovery appraised separate fault block and flowed at restricted rate of 5,600 bbls/d from one interval ---------------------------------------------------------------------------------------------------------------------- 2003 Ukot-2 3.5 km south of discovery encountered three oil-bearing intervals ---------------------------------------------------------------------------------------------------------------------- 2003 Usan-4 5 km south of discovery flowed at restricted rate of 4,400 bbls/d from first interval and 6,300 bbls/d from second interval ---------------------------------------------------------------------------------------------------------------------- 2004 Usan-5 6 km west of discovery sampled oil in several intervals ---------------------------------------------------------------------------------------------------------------------- 2004 Usan-6 4 km south of Usan-5 flowed at restricted rate of 5,800 bbls/d from one interval ---------------------------------------------------------------------------------------------------------------------- 2005 Usan-7 9 km southwest of discovery confirmed an eastern extension of the field ---------------------------------------------------------------------------------------------------------------------- 2005 Usan-8 3 km southwest of discovery confirmed an eastern extension of the field ----------------------------------------------------------------------------------------------------------------------
13 The Usan-7 and Usan-8 appraisal wells were successfully drilled during the year. Appraisal of this field is now complete, and a preliminary field development plan has been submitted to Nigerian governmental agencies for approval. The plan features a multi-well development of Usan connected to a two-million-barrel floating production, storage and offloading vessel (FPSO) by subsea flowlines and risers. The peak design capacity of the FPSO is 160,000 bbls/d. In 2005, we drilled the deep-water Efere well. This well was unsuccessful and the capital costs were expensed. BLOCK OML-115 The Nigerian Government formally approved the Deed of Assignment for OML-115 in December 2003, which assigned us a 40% interest in the block. In 2004, we drilled a well on the Ameena prospect and did not find hydrocarbons. In 2006, we plan to conduct geological and geophysical studies to further evaluate the block. BLOCK OML-109--EJULEBE Ejulebe production averaged 200 bbls/d for the year. In June, we sold our assets and terminated our contractual interest in this block. EQUATORIAL GUINEA--BLOCK K In 2003, we acquired a 25% operated interest in Block K, a deep-water block located 100 km off-shore Equatorial Guinea. This interest was later increased to 50%. In 2004 and 2005, we drilled two exploration wells and found non-commercial quantities of hydrocarbons. In 2006, we plan to make a recommendation to the partners on future participation in this block. OTHER INTERNATIONAL COLOMBIA BOQUERON BLOCK--GUANDO In 2000, we made our first discovery at Guando on our 20% non-operated Boqueron Block. Boqueron is in the Upper Magdalena Basin of central Colombia, approximately 45 km southwest of Bogota. Our share of 2005 production averaged 5,400 bbls/d before royalties (5,000 after royalties), about 2% of Nexen's total production. Production from Guando is subject to a 5% to 25% royalty depending on daily production. The corporate income tax rate is 38.5%. EXPLORATION BLOCKS We are assessing potential drilling opportunities on our interests in three other exploration blocks in the Upper Magdalena Basin. Villarrica was acquired in 2000, El Queso in 2003 and Boqueron Deep in 2003. In 2005, we relinquished the Villarrica Block and acquired the Villarrica Norte Block under improved fiscal terms. In 2006, we plan to drill three exploration wells. AUSTRALIA--BUFFALO Field abandonment began in November 2004 and was completed in 2005. RESERVES, PRODUCTION AND RELATED INFORMATION In addition to the tables below, we refer you to the Supplementary Data in Item 8 of this Form 10-K for information on our oil and gas producing activities. Nexen has not filed with nor included in reports to any other United States federal authority or agency, any estimates of total proved crude oil or natural gas reserves since the beginning of the last fiscal year. Net Sales by Product from Continuing Oil and Gas Operations (including Syncrude) -------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 -------------------------------------------------------------------------------- Conventional Crude Oil and Natural Gas Liquids 2,438 1,697 1,449 (NGLs) -------------------------------------------------------------------------------- Synthetic Crude Oil 397 321 240 -------------------------------------------------------------------------------- Natural Gas 671 534 547 -------------------------------------------------------------------------------- Total 3,506 2,552 2,236 -------------------------------------------------------------------------------- Crude oil (including synthetic crude oil) and natural gas liquids represent approximately 81% of our oil and gas net sales, while natural gas represents the remaining 19%. 14
Sales Prices and Production Costs (excluding Syncrude) --------------------------------------------------------------------------------------------------------------------- Average Sales Price (1) Average Production Cost (1) --------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 2005 2004 2003 --------------------------------------------------------------------------------------------------------------------- Crude Oil and NGLs (Cdn$/bbl) --------------------------------------------------------------------------------------------------------------------- Yemen 62.07 47.59 39.45 6.75 5.64 4.37 --------------------------------------------------------------------------------------------------------------------- Canada (2) 40.51 36.60 32.37 14.01 11.76 10.00 --------------------------------------------------------------------------------------------------------------------- United States 57.63 46.60 37.68 7.33 6.09 5.08 --------------------------------------------------------------------------------------------------------------------- United Kingdom 60.55 46.81 - 14.90 8.26 - --------------------------------------------------------------------------------------------------------------------- Australia (2) - 51.22 43.14 - 35.73 20.21 --------------------------------------------------------------------------------------------------------------------- Other Countries 59.96 43.07 38.22 6.08 4.09 9.01 --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Natural Gas (Cdn$/mcf) --------------------------------------------------------------------------------------------------------------------- Canada (2) 7.51 5.76 5.64 0.95 0.85 0.65 --------------------------------------------------------------------------------------------------------------------- United States 10.56 7.89 8.16 1.22 1.02 0.89 --------------------------------------------------------------------------------------------------------------------- United Kingdom 7.86 8.28 - 2.48 - - ---------------------------------------------------------------------------------------------------------------------
Notes: 1 Sales prices and unit production costs are calculated using our working interest production after royalties. 2 Includes results of discontinued operations. (See Note 14 to our Consolidated Financial Statements.)
Producing Oil and Gas Wells ----------------------------------------------------------------------------------------------------------------------- 2005 ----------------------------------------------------------------------------------------------------------------------- Oil Gas Total ----------------------------------------------------------------------------------------------------------------------- (number of net wells) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) ----------------------------------------------------------------------------------------------------------------------- United States 198 89 195 135 393 224 ----------------------------------------------------------------------------------------------------------------------- Yemen 400 220 - - 400 220 ----------------------------------------------------------------------------------------------------------------------- United Kingdom 33 14 - - 33 14 ----------------------------------------------------------------------------------------------------------------------- Canada 2,321 1,625 2,457 2,161 4,778 3,786 ----------------------------------------------------------------------------------------------------------------------- Colombia 79 17 - - 79 17 ----------------------------------------------------------------------------------------------------------------------- Total 3,031 1,965 2,652 2,296 5,683 4,261 -----------------------------------------------------------------------------------------------------------------------
Notes: 1 Gross wells are the total number of wells in which we own an interest. 2 Net wells are the sum of fractional interests owned in gross wells.
Oil and Gas Acreage ------------------------------------------------------------------------------------------------------------------------ 2005 ------------------------------------------------------------------------------------------------------------------------ Developed Undeveloped (1) Total ------------------------------------------------------------------------------------------------------------------------ (thousands of acres) Gross Net Gross Net Gross Net ------------------------------------------------------------------------------------------------------------------------ United States 183 103 1,445 606 1,628 709 ------------------------------------------------------------------------------------------------------------------------ Yemen (2) 50 29 756 628 806 657 ------------------------------------------------------------------------------------------------------------------------ Nigeria (2, 3) - - 510 114 510 114 ------------------------------------------------------------------------------------------------------------------------ Equatorial Guinea - - 1,106 553 1,106 553 ------------------------------------------------------------------------------------------------------------------------ Canada 702 531 2,120 1,109 2,822 1,640 ------------------------------------------------------------------------------------------------------------------------ Colombia (4) 1 - 604 463 605 463 ------------------------------------------------------------------------------------------------------------------------ United Kingdom 83 27 1,851 963 1,934 990 ------------------------------------------------------------------------------------------------------------------------ Total 1,019 690 8,392 4,436 9,411 5,126 ------------------------------------------------------------------------------------------------------------------------
Notes: 1 Undeveloped acreage is considered to be those acres on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. 2 The acreage is covered by production sharing contracts. 3 The acreage is covered by a joint venture agreement. 4 The acreage is covered by an association contract. 15
Drilling Activity ----------------------------------------------------------------------------------------------------------------------- 2005 ----------------------------------------------------------------------------------------------------------------------- Net Exploratory Net Development Total ----------------------------------------------------------------------------------------------------------------------- (number of net wells) Dry Productive Productive Holes Total Holes Dry Total ----------------------------------------------------------------------------------------------------------------------- United States - 0.6 0.6 7.2 1.0 8.2 8.8 ----------------------------------------------------------------------------------------------------------------------- United Kingdom 0.5 2.1 2.6 1.5 - 1.5 4.1 ----------------------------------------------------------------------------------------------------------------------- Yemen 0.5 4.6 5.1 33.0 1.6 34.6 39.7 ----------------------------------------------------------------------------------------------------------------------- Nigeria 0.4 0.2 0.6 - - - 0.6 ----------------------------------------------------------------------------------------------------------------------- Canada 32.2 8.0 40.2 198.9 0.5 199.4 239.6 ----------------------------------------------------------------------------------------------------------------------- Colombia - - - 1.8 - 1.8 1.8 ----------------------------------------------------------------------------------------------------------------------- Equatorial Guinea - 0.5 0.5 - - - 0.5 ----------------------------------------------------------------------------------------------------------------------- Total 33.6 16.0 49.6 242.4 3.1 245.5 295.1 ----------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------- 2004 ----------------------------------------------------------------------------------------------------------------------- Net Exploratory Net Development Total ----------------------------------------------------------------------------------------------------------------------- (number of net wells) Dry Productive Productive Holes Total Holes Dry Total ----------------------------------------------------------------------------------------------------------------------- United States 0.3 1.8 2.1 11.0 1.0 12.0 14.1 ----------------------------------------------------------------------------------------------------------------------- United Kingdom - - - - - - - ----------------------------------------------------------------------------------------------------------------------- Yemen - 2.0 2.0 37.3 0.5 37.8 39.8 ----------------------------------------------------------------------------------------------------------------------- Nigeria 0.4 1.0 1.4 - - - 1.4 ----------------------------------------------------------------------------------------------------------------------- Canada 13.4 1.0 14.4 202.9 - 202.9 217.3 ----------------------------------------------------------------------------------------------------------------------- Colombia - - - 7.0 - 7.0 7.0 ----------------------------------------------------------------------------------------------------------------------- Equatorial Guinea - 0.5 0.5 - - - 0.5 ----------------------------------------------------------------------------------------------------------------------- Total 14.1 6.3 20.4 258.2 1.5 259.7 280.1 ----------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------- 2003 ----------------------------------------------------------------------------------------------------------------------- Net Exploratory Net Development Total ----------------------------------------------------------------------------------------------------------------------- (number of net wells) Dry Productive Productive Holes Total Holes Dry Total ----------------------------------------------------------------------------------------------------------------------- United States - 0.5 0.5 8.3 0.1 8.4 8.9 ----------------------------------------------------------------------------------------------------------------------- Yemen 8.0 1.0 9.0 49.0 - 49.0 58.0 ----------------------------------------------------------------------------------------------------------------------- Nigeria 0.6 - 0.6 - - - 0.6 ----------------------------------------------------------------------------------------------------------------------- Canada 15.4 1.7 17.1 157.7 2.5 160.2 177.3 ----------------------------------------------------------------------------------------------------------------------- Colombia - 1.0 1.0 6.2 - 6.2 7.2 ----------------------------------------------------------------------------------------------------------------------- Brazil - 0.2 0.2 - - - 0.2 ----------------------------------------------------------------------------------------------------------------------- Total 24.0 4.4 28.4 221.2 2.6 223.8 252.2 -----------------------------------------------------------------------------------------------------------------------
WELLS IN PROGRESS At December 31, 2005, we were drilling 7 wells in the United States (4.0 net), 15 wells in Canada (8.6 net), 4 wells in Yemen (3.0 net), 1 well in Colombia (0.2 net), and 2 wells in the UK (0.8 net). 16 RESERVES PROVED UNDEVELOPED RESERVES The following table provides a summary of our proved undeveloped reserves (PUDs) at December 31, 2005:
----------------------------------------------------------------------------------------------------------- Before Royalties After Royalties ----------------------------------------------------------------------------------------------------------- (mmboe) Total % of Total % of PUDs Proved Total PUDs Proved Total ----------------------------------------------------------------------------------------------------------- United Kingdom 128 145 88 128 145 88 ----------------------------------------------------------------------------------------------------------- Yemen 23 105 22 13 59 22 ----------------------------------------------------------------------------------------------------------- United States 15 90 17 13 77 17 ----------------------------------------------------------------------------------------------------------- Canada 13 117 11 11 101 11 ----------------------------------------------------------------------------------------------------------- Other 1 11 5 - 11 5 ----------------------------------------------------------------------------------------------------------- 180 468 38 165 393 42 -----------------------------------------------------------------------------------------------------------
In the United Kingdom, the PUDs relate almost entirely to our Buzzard Field. We are in the process of drilling and completing the initial development wells. Construction and installation of the facilities is complete and commissioning work is underway. The field came on-stream in early 2007. This activity is expected to result in 75% of the PUDs being converted to producing upon start-up of the facility. The remaining PUDs are expected to be converted to producing over the next 4 years as we drill the remaining development wells based on available facility capacity. In Yemen, the PUDs are split relatively equally between our Masila and East Al Hajr Blocks. These reserves relate entirely to infill drilling, some of which occured during 2006 and is planned for 2007. In the United States, the PUDs are split equally between our Shelf and deep-water activities. The majority of these reserves relate to infill drilling programs on 11 properties. These programs are either taking place during 2006 or are planned for 2007. In addition, a portion of the PUDs relate to our deep-water Wrigley subsea tie-back development which is currently underway. In Canada, the majority of the PUDs relate to infill drilling, recompletions or facilities enhancements on our various heavy oil and natural gas fields. The majority of these PUDs are expected to be converted to producing reserves in 2006 and 2007. A small portion of the PUDs relate to our Coal Bed Methane properties which are expected to be converted to producing from infill drilling and field development from activities in 2006 or planned for 2007. In total, we expect to convert about 85% of these PUDs to producing over the next 3 years. At the same time, we expect our ongoing exploration and development activities to continue to add new PUDs. Reserve estimates in this report are internally prepared. Refer to the section on Critical Accounting Estimates - Oil and Gas Accounting - Reserves Determination on page 59 for a description of our reserves process. As described therein, we have at least 80% of our oil and gas reserves estimates either evaluated or audited annually by independent qualified reserves consultants. The nature and scope of the evaluations and audits is determined by agreement between us and the engineering firm. Independent assessments for other companies may, therefore, be different. BASIS OF RESERVES ESTIMATES The following provides an overview of the nature and scope of the independent evaluations and audits that we have performed. An independent evaluation is a process whereby we request a third-party engineering firm to prepare an estimate of our reserves by assessing and interpreting all available data on a reservoir. An independent audit is a process whereby we request a third party engineering firm to prepare an estimate of our reserves by reviewing our estimates, supporting working papers and other data as they feel is necessary. The primary difference is that an auditor reviews our work and estimate in preparing their estimate whereas an evaluator uses the reservoir data to prepare their estimate. In each case, we request their estimate to be prepared using standard geological and engineering methods generally accepted by the petroleum industry. Generally accepted methods for estimating reserves include volumetric calculations, material balance techniques, production and pressure decline curve analysis, analogy with similar reservoirs, and reservoir simulation. The method or combination of methods used is based on their professional judgement and experience. In preparing their estimates, they obtain information from us with respect to property interests, production from such properties, current costs of operations, future development and abandonment, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data. They may rely on the information without independent verification. However, if in the course of their evaluation they question the validity or sufficiency of any information, we request that they do not rely on such information until they satisfactorily resolve their questions or independently verify such information. We do not place any limitations on the work to be performed. Upon completion of their 17 work, the independent evaluator or auditor issues an opinion as to whether our estimate of the proved reserves for that portfolio of properties is, in aggregate, reasonable relative to the criteria set forth in SEC Rule 4-10(a)(2) of Regulation S-X. These rules define proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our estimate may differ from the independent evaluators and auditors as they apply their professional judgement and experience, which may result in applying different estimating methods or interpreting data differently than us. We believe our estimate for a portfolio of properties is reasonable when it is, in aggregate, within 10% of the independent evaluator or auditor. We engaged DeGolyer and MacNaughton ("D&M") to evaluate 100% of our reserves before royalties (100% after royalties) for the United Kingdom, Yemen Masila and Yemen Block 51. A separate opinion was provided on each of these three areas. D&M provided an opinion on each of the areas that the proved reserves estimate prepared by us is, in aggregate, reasonable when compared to their estimate which was prepared in accordance with SEC Rules. We engaged McDaniel & Associates Consultants Ltd. ("McDaniel") to evaluate 91% of our Canadian conventional and CBM reserves before royalties (91% after royalties) and to audit 100% of our Syncrude mining reserves before royalties (100% after royalties). The properties were selected by management and reviewed with the Reserves Review Committee of the Board. All material properties were selected. McDaniel provided an opinion on the combined Canadian conventional, CBM and Syncrude reserves that the proved reserves estimate prepared by us is, in aggregate, within 10% of their estimate which was prepared in accordance with SEC Rules. We engaged Ryder Scott Company ("Ryder Scott") to audit 76% of our U.S. Gulf of Mexico shelf reserves before royalties (76% after royalties). The properties were selected by management and reviewed with the Reserves Review Committee of the Board. All material properties were selected. Ryder Scott provided an opinion that the difference between their estimate and ours is within the range of reasonable differences and that the estimates have been prepared in accordance with SEC Rules. We engaged William M. Cobb & Associates, Inc. ("Cobb") to audit 100% of our U.S. Gulf of Mexico deep-water reserves before royalties (100% after royalties). Cobb provided an opinion that the difference between their estimate and ours is within the range of reasonable differences and that the estimates have been prepared in accordance with SEC Rules. SYNCRUDE MINING OPERATIONS We hold a 7.23% participating interest in Syncrude Canada Ltd. (Syncrude). This joint venture was established in 1975 to mine shallow oil sands deposits using open-pit mining methods, extract the bitumen from the oil sands and upgrade the bitumen to produce a high-quality, light (32* API), sweet, synthetic crude oil. The Syncrude operation exploits a portion of the Athabasca oil sands deposit that contains bitumen in the unconsolidated sands of the McMurray formation. Ore bodies are buried beneath 50 to 150 feet of over-burden, have bitumen grades ranging from 4 to 14 percent by weight and ore bearing sand thickness of 100 to 160 feet. Syncrude's operations are on eight leases (10, 12, 17, 22, 29, 30, 31, and 34) covering 258,000 hectares, 40 km north of Fort McMurray in northeast Alberta. Syncrude mines oil sands at three mines: Base, North, and Aurora North. These locations are readily accessible by public road. At the Base Mine (lease 17), a dragline, bucket-wheel reclaimers, and belt conveyors are used for mining and transporting oil sands. In the North Mine (leases 17 and 22) and in the Aurora North Mine (leases 10, 12, and 34), a truck-and-shovel and hydro-transport system is used. The extraction facilities, which separate bitumen from oil sands, are capable of processing more than 260 million tons of oil sands per year and about 146 mmbbls of bitumen per year. To extract bitumen, the oil sands are mixed with water to form a slurry. Air and chemicals are added to separate bitumen from the sand grains. The process at the Base Mine uses hot water, steam, and caustic soda to create a slurry, while at the North Mine and the Aurora North Mine, the oil sands are mixed with warm water to produce a slurry. The extracted bitumen is fed into a vacuum distillation tower and two cokers for primary upgrading. The resulting products are then separated into naphtha, light gas oil, and heavy gas-oil streams. These streams are hydrotreated to remove sulphur and nitrogen impurities to form light, sweet, synthetic crude oil. Sulphur and coke, which are by-products of the process, are stockpiled for possible future sale. In 2005, the upgrading process yielded 0.85 barrels of synthetic crude oil per barrel of bitumen. The high quality of Syncrude's synthetic crude oil typically means it is sold at a premium to WTI. In 2005, about 49% of the synthetic crude oil was sold to Edmonton area refineries, and the remaining 51% was sold to refineries in Eastern Canada and the mid-Western United States. 18 Electricity is provided to Syncrude from two generating plants: a 270 MW plant and an 80 MW plant. Both plants are at Syncrude and owned by the Syncrude participants. Since operations started in 1978, Syncrude has shipped more than 1.6 billion barrels of synthetic crude oil to Edmonton, Alberta, by Alberta Oil Sands Pipeline Ltd. The pipeline was expanded in 2004 to accommodate increased Syncrude production. At year-end 2005, our total investment in the property, plant and equipment, including surface mining facilities, transportation equipment, and upgrading facilities, was approximately $1.2 billion. Based on development plans, our share of future expansion and equipment replacement costs over the next 35 years is expected to be about $1.5 billion. In 1999, the Alberta Energy and Utilities Board (AEUB) extended Syncrude's operating license for the eight oil sands leases through to 2035. The license permits Syncrude to mine oil sands and produce synthetic crude oil from approved development areas on the oil sands leases. The leases are automatically renewable as long as oil sands operations are ongoing or the leases are part of an approved development plan. All eight leases are included in a development plan approved by the AEUB. There were no known commercial operations on these leases prior to the start-up of operations in 1978. Syncrude pays a royalty to the Province of Alberta. Subsequent to 1987, this royalty was equal to 50% of Syncrude's deemed net profits after deduction of capital expenditures. In 1995, the Province of Alberta announced generic royalty terms for new oil sands projects that provide for a royalty rate of 25% on net revenues after all costs have been recovered, subject to a minimum 1% gross royalty. In 1997, the Province of Alberta and the Syncrude owners agreed to move to the generic royalty terms when the total of all allowed capital costs incurred after December 31, 1995 equalled $2.8 billion (gross). That total was surpassed at the end of 2001. In 2005, Syncrude was subject to the minimum 1% gross royalty. In 2006, we expect to complete full recovery of allowed capital costs and, as a result, we expect Syncrude royalties to be assessed at 25% of net revenues. In 1999, the AEUB approved an increase in Syncrude's production capacity to 465,700 bbls/d. At the end of 2001, Syncrude had increased its synthetic crude oil capacity to 246,500 bbls/d with the development of the Aurora North Mine, which involved extending mining operations to a new location about 25 miles north of the main Syncrude site. In 2001, the Syncrude owners approved the third stage of the Syncrude expansion, which will increase capacity to 360,000 bbls/d in 2006. With higher engineering, manufacturing and construction costs, the estimated costs of the Stage 3 expansion have increased from initial estimates of $4.1 billion to $8.4 billion. Nexen's share of the project costs is $600 million, of which $568 million had been incurred by year end 2005. Activities in 2006 are focused on completion and start-up of the Stage 3 expansion and base plant maintenance. Our share of capital spending in 2006 is expected to be $80 million. In 2005, Syncrude's production of marketable synthetic crude oil was 214,000 bbls/d. Nexen's share was 15,500 bbls/d before royalties (15,300 bbls/d after royalties). 19 The following table provides some operating statistics for Syncrude operations: -------------------------------------------------------------------------------- 2005 2004 2003 -------------------------------------------------------------------------------- Total Mined Volume (1) -------------------------------------------------------------------------------- Millions of Tons 353 389 380 -------------------------------------------------------------------------------- Mined Volume to Oil Sands Ratio (1) 2.1 2.1 2.3 -------------------------------------------------------------------------------- Oil Sands Processed -------------------------------------------------------------------------------- Millions of Tons 169 188 168 -------------------------------------------------------------------------------- Average Bitumen Grade (weight %) 11.1 11.1 11.0 -------------------------------------------------------------------------------- Bitumen in Mined Oil Sands -------------------------------------------------------------------------------- Millions of Tons 19 21 18 -------------------------------------------------------------------------------- Average Extraction Recovery (%) 89 87 89 -------------------------------------------------------------------------------- Bitumen Production (2) -------------------------------------------------------------------------------- Millions of Barrels 94 103 92 -------------------------------------------------------------------------------- Average Upgrading Yield (%) 85 86 86 -------------------------------------------------------------------------------- Gross Synthetic Crude Oil Shipped (3) -------------------------------------------------------------------------------- Millions of Barrels 78 87 77 -------------------------------------------------------------------------------- Nexen's Share of Marketable Crude Oil -------------------------------------------------------------------------------- Millions of Barrels Before Royalties 5.7 6.3 5.6 -------------------------------------------------------------------------------- Millions of Barrels After Royalties 5.6 6.1 5.5 -------------------------------------------------------------------------------- Notes: 1 Includes pre-stripping of mine areas and reclamation volumes. 2 Bitumen production in barrels is equal to bitumen in mined oil sands multiplied by the average extraction recovery and the appropriate conversion factor. 3 Approximately 1.2% of the produced synthetic crude oil is used internally at Syncrude. The remaining synthetic crude oil is sold externally. OIL AND GAS MARKETING Our marketing group sells proprietary and third-party natural gas, crude oil, natural gas liquids and power in certain regional markets where we have built a solid strategic presence. This includes access to transportation, storage and facilities, as well as crude oil and natural gas we produce or acquire. We optimize the margin on our base business by trading around our access to these physical assets when market opportunities present themselves. We use financial and derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes. Our marketing strategy is to: o obtain competitive pricing on the sale of our own oil and gas production; o provide market intelligence in support of our oil and gas operations; o provide superior customer service to producers and consumers; and o capitalize on market opportunities through low-risk trading related to our transportation and storage assets. This strategy aligns with our corporate focus on extracting full value from our assets and provides us with the market intelligence needed to deliver our current and future oil and gas production to market at competitive pricing. GAS MARKETING The marketing and trading of natural gas is our marketing group's largest revenue stream. We focus on key regional markets where we have a strategic presence--solid customer relationships, in-depth understanding of the market or established physical trading-based assets. We capture regional opportunities by managing supply, transportation and storage assets for producers and end users. In addition to the fee-for-service income we realize from managing these assets, we generate further revenue by: o capitalizing on location spreads (differences in prices between market locations) using our transportation assets; and o capitalizing on time spreads (differences in prices between summer and winter) using our storage assets. We have offices in key regions including Calgary, Detroit and Houston. Our Calgary office provides a variety of services, including supply, storage, and transportation management as well as netback pool arrangements and other customer services. Our customers include producers and consumers in Western Canada as well as consumers (including utilities) in Eastern Canada, the Northeastern United States and the US mid-continent. Our offices in Detroit and Calgary work together to provide services to our customers. Our presence in Houston has established us in the Gulf Coast region where we have our own production. We use our access to transportation and storage facilities to optimize returns for ourselves as well as our customers. 20 In 2003 and 2004, we grew our asset base by acquiring physical gas purchase and sales contracts, as well as natural gas transportation capacity on favourable terms. This has given us access to new third party gas supply until 2008, pipeline capacity to 2016 and new relationships that have enabled us to negotiate new gas purchase and sales contracts. Our position as a physical marketer at multiple delivery points in key markets gives us the flexibility to capitalize on time and location spreads. With pipeline capacity, we can move gas from producing regions to take advantage of price differences. At the end of 2005, we held 4 bcf/d of pipeline capacity, primarily between Western Canada and Eastern US. We also use storage capacity to store typically cheaper summer gas in the ground until the winter heating season arrives. We had access to 30 bcf of natural gas storage facilities at the end of the year. In addition to transportation and storage assets, we hold financial contracts that enable us to capture profits around time and location spreads. The basis risk we assume on these contracts is based on solid fundamental analysis and in-depth knowledge of regional markets. The risk is managed proactively by our product group teams and monitored closely by our risk group, with regular reporting to management and the Board. CRUDE OIL MARKETING Our crude oil business focuses on marketing physical crude oil to end-use refiners. The crude oil group markets our own production and more than 500,000 bbls/d of third-party field production to refiners from producing regions where we operate. In addition to physical marketing, we take advantage of quality differentials and time spreads. Our North American operations focus on key regions supported by our offices in Calgary and Houston. In Western Canada, our producer services group concentrates on the procurement of a diversified supply base, while our trading team seeks to optimize the mix for sale to refiners. Traditionally, the Chicago and Denver areas have been key markets for our Western Canadian crude, however, recently we have expanded our presence into the US gulf coast. Our deep-water Gulf of Mexico crude oil production has given us the opportunity to expand our presence in that market through our Houston office. Internationally, we focus on the physical marketing of our Yemen crude oil. In order to meet customer needs, we may occasionally market other regional crude types. In addition to our own crude, we market production for our partners and third parties in the Yemen region. By locating our international crude oil marketing office in Singapore, we are well positioned to serve both the producing region and the Asian refining market. During the year, we added an office in London, in the United Kingdom, to begin maximizing the value of our North Sea production. As Buzzard crude comes on stream in late 2006, we expect to increase our presence in various European markets, ensuring we maximize the value of this production. Our crude oil marketing group also holds financial contracts that enable us to capture trading profits around time, quality and location spreads. Like gas marketing, the basis risk assumed is based on solid fundamental analysis and proprietary knowledge of regional markets, and it is managed and monitored closely by our risk group. POWER MARKETING Our power marketing group is responsible for optimizing the use of our 100 MW gas-fired, combined-cycle power generation facility at Balzac, Alberta, and for marketing power to larger commercial, industrial and municipal clients in Alberta. With our recent acquisition of a commercial/industrial business in Alberta, we have become the largest supplier of power to the commercial and industrial sectors in the province. Our Balzac facility began operations in 2001. We expect to increase our power generation capacity with a 170 MW co-generation facility at Long Lake in 2007, and through our 70 MW Soderglen wind power project in southern Alberta in 2006. We have a 50% interest in each project. 21 CHEMICALS In 2005, we monetized part of our chemicals business through an initial public offering of the Canexus Income Fund. We have retained a 61.4% indirect interest in our chemicals business, and we continue to fully consolidate chemicals in our consolidated financial statements. Our chemicals business manufactures sodium chlorate and chlor-alkali products (chlorine, caustic soda and muriatic acid) in Canada and Brazil. This production is sold in North and South America, with some sodium chlorate distributed in Asia. Our manufacturing facilities are modern, reliable and strategically located to capitalize on competitive power costs or transportation infrastructure to minimize production and delivery costs. This enables us to have reliable supplies and low costs--key factors for marketing bleaching chemicals. Electricity is the most significant operating cost in producing sodium chlorate and chlor-alkali products, making up over half our cash costs. Therefore, our current facilities are strategically located to take advantage of economic power sources. Our second highest cost is transportation. Our sales are concentrated mainly in North America and Brazil with a small amount of sodium chlorate sold in Asia. The proximity of our manufacturing plants to major customers and competitive freight rates minimizes our transportation costs. Labour is also a significant manufacturing cost. Approximately 50% of our workforce is unionized with collective agreements in place at all of our unionized plants. To grow value in our chemicals business, we focus on improving our costs while maintaining market share, building a sustainable North American customer base and capturing new offshore opportunities. Average Annual Production Capacity ------------------------------------------------------------------------------ (short tons) 2005 2004 2003 ------------------------------------------------------------------------------ Sodium Chlorate ------------------------------------------------------------------------------ North America 446,208 446,617 432,812 ------------------------------------------------------------------------------ Brazil 68,563 68,563 68,563 ------------------------------------------------------------------------------ Total 514,771 515,180 501,375 ------------------------------------------------------------------------------ Chlor-alkali ------------------------------------------------------------------------------ North America 356,002 356,002 356,002 ------------------------------------------------------------------------------ Brazil 109,430 109,430 109,430 ------------------------------------------------------------------------------ Total 465,432 465,432 465,432 ------------------------------------------------------------------------------ NORTH AMERICA The North American pulp and paper industry consumes approximately 95% of the continent's sodium chlorate production. We market our sodium chlorate production to numerous pulp and paper mills under multi-year contracts that contain price and volume provisions. Approximately 31% of this production is sold in Canada, 62% in the US, and the rest is marketed offshore. We are the third-largest manufacturer of sodium chlorate in North America with four Canadian facilities: Nanaimo, British Columbia; Bruderheim, Alberta; Brandon, Manitoba; and Beauharnois, Quebec. In October 2004, we completed an expansion of our plant in Brandon, Manitoba increasing capacity to 260,000 tonnes per year. This expansion replaced higher-cost capacity idled in 2002 at Taft, Louisiana. Brandon is the world's largest sodium chlorate facility and has one of the lowest cost structures in the industry, significantly enhancing our competitive position in North America. During the year, we closed our plant at Amherstburg, Ontario. Our chlor-alkali facility at North Vancouver, British Columbia, manufactures caustic soda, chlorine and muriatic acid. Almost all of our caustic soda is consumed by local pulp and paper mills, while our chlorine is sold to various customers in the polyvinyl chloride, water purification and petrochemicals industries, primarily in the United States. BRAZIL We entered Brazil in 1999 by acquiring a sodium chlorate plant and a chlor-alkali plant from Aracruz Cellulose S.A. (Aracruz), the leading manufacturer of pulp in Brazil. The majority of the production is sold to Aracruz under a long-term sales agreement that expires in 2024. This agreement had an initial six-year take-or-pay component that ended in 2005. Most of the chlorine and about 20% of the sodium chlorate production is sold in the merchant market under shorter-term contractual arrangements. In 2002, we completed an expansion at both facilities to meet Aracruz's growing needs. The majority of our electricity needs are supplied by a long-term supply contract in Brazil. ADDITIONAL FACTORS AFFECTING BUSINESS See Item 7 of this Form 10-K. 22 GOVERNMENT REGULATIONS Our operations are subject to various levels of government controls and regulations in the countries where we operate. These laws and regulations include matters relating to land tenure, drilling, production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment, that are subject to change from time to time. Current legislation is generally a matter of public record, and we are unable to predict what additional legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective. We participate in many industry and professional associations and monitor the progress of proposed legislation and regulatory amendments. ENVIRONMENTAL REGULATIONS Our oil and gas and chemical operations are subject to government laws and regulations designed to protect and regulate the discharge of materials into the environment in countries where we operate. We believe our operations comply in all material respects with applicable environmental laws. To reduce our exposure, we apply industry standards, codes and best practices to meet or exceed these laws and regulations. Occasionally, we may conduct activities in countries where environmental regulatory frameworks are in various stages of evolution. Where regulations are lacking, we observe Canadian standards where applicable, as well as internationally accepted industry environmental management practices. We have an active safety, environment and social responsibility group that ensures our worldwide operations are conducted in a safe, ethical and socially responsible manner. We have developed policies for continuing compliance with environmental laws and regulations in the countries in which we operate. ENVIRONMENTAL PROVISIONS AND EXPENDITURES The ultimate financial impact of environmental laws and regulations is not clearly known and cannot be reasonably estimated as new standards continue to evolve in the countries in which we operate. We estimate our future environmental costs based on past experience and current regulations. At December 31, 2005, $611 million ($1,471 million, undiscounted) has been provided in our Consolidated Financial Statements for asset retirement obligations for our oil and gas, Syncrude and chemicals facilities. In 2005, we increased our retirement obligations for future dismantlement and site restoration by $210 million primarily from increased drilling and development activities in the Gulf of Mexico, North Sea, Canada and Yemen, general industry cost pressures and more stringent environmental laws and regulations. In 2005, our capital expenditures for environmental-related matters, including environment control facilities, were approximately $34 million. Our operating expenditures for environmental-related matters were approximately $35 million. In 2006, we estimate these expenditures to be approximately $21 million. EMPLOYEES We had 3,282 employees on December 31, 2005, of which 301 were employed under collective bargaining schemes. Information on our executive officers is presented in Item 10 of this report. 23 PART II ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION Page Executive Summary of 2005 Results ...........................................25 Capital Investment ..........................................................26 Financial Results Year-to-Year Change in Net Income .......................................30 Oil & Gas and Syncrude Production ..........................................................31 Commodity Prices ....................................................34 Operating Costs .....................................................36 Depreciation, Depletion, Amortization and Impairment ................37 Exploration Expense .................................................38 Oil & Gas and Syncrude Netbacks .........................................40 Oil and Gas Marketing ...................................................41 Chemicals ...............................................................43 Corporate Expenses ......................................................44 Outlook for 2006 ............................................................46 Liquidity and Capital Resources .............................................48 Risk Factors ................................................................53 Critical Accounting Estimates ...............................................59 Quantitative and Qualitative Disclosures about Market Risk ..................64 The following should be read in conjunction with the Consolidated Financial Statements included in this report. The Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. The impact of significant differences between Canadian and United States (US) accounting principles on the financial statements is disclosed in Note 21 to the Consolidated Financial Statements. The date of this discussion is February 7, 2006. Unless otherwise noted, tabular amounts are in millions of Canadian dollars. Our discussion and analysis of our oil and gas activities include our Syncrude activities since the product produced from Syncrude competes in the oil and gas market. Oil and gas volumes, reserves and related performance measures are presented on a working interest before-royalties basis. We measure our performance in this manner consistent with other Canadian oil and gas companies. Where appropriate, we have provided information on an after-royalty basis in tabular format. Note: Canadian investors should read the Special Note to Canadian Investors on page 69 which highlights differences between our reserve estimates and related disclosures that are otherwise required by Canadian regulatory authorities. 24
EXECUTIVE SUMMARY OF 2005 RESULTS ----------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ----------------------------------------------------------------------------------------- Net Income 1,152 793 578 ----------------------------------------------------------------------------------------- Earnings per Common Share ($/share) 4.43 3.08 2.33 ----------------------------------------------------------------------------------------- Cash Flow from Operating Activities 2,143 1,606 1,405 ----------------------------------------------------------------------------------------- Production before Royalties (mboe/d) (1) 242 250 269 ----------------------------------------------------------------------------------------- Production after Royalties (mboe/d) 173 174 185 ----------------------------------------------------------------------------------------- Capital Investment, including Acquisitions 2,638 4,264 1,494 ----------------------------------------------------------------------------------------- Net Debt (2) 3,641 4,219 1,690 ----------------------------------------------------------------------------------------- Average Foreign Exchange Rate (Canadian to US dollar) 0.83 0.77 0.71 -----------------------------------------------------------------------------------------
Notes: (1) Production before royalties reflects our working interest before royalties and includes production of synthetic crude oil from Syncrude. We have presented our working interest before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Long-term debt less working capital. We achieved record financial results in 2005 with net income exceeding $1 billion for the first time in company history. We exceeded our production targets, notwithstanding the sale of oil and gas properties in Canada and the impact of hurricanes in the US. We also successfully reduced our net debt while managing our largest capital program ever. We made significant progress on our strategic initiatives by moving closer to first production at Buzzard and Long Lake, beginning commercial CBM development at Corbett, Doris and Thunder and making a potentially significant discovery at Knotty Head in the US Gulf. In addition, we received record net revenues from our marketing group. Record high commodity prices throughout the year underpinned our results. We also realized a gain of $225 million on disposition of Canadian conventional oil and gas properties, and a gain of $193 million on the initial public offering of a portion of our chemicals business through the Canexus Income Fund. We raised more than $1.4 billion from these transactions and used the proceeds to reduce net debt and fund our capital programs. Our major capital projects remain on time and on budget. Buzzard is approximately 88% complete and we are on track for first production in late 2006. Peak production is expected to be approximately 200,000 boe/d (85,000 boe/d net to us), royalty free. Our Long Lake project is now more than 30% complete and we are on track to complete and tie-in our commercial SAGD wells and begin steam injection late in 2006. Production is expected to ramp up before the upgrader is complete in the second half of 2007. We expect our share of synthetic crude oil from Long Lake to be 30,000 bbls/d. We are already planning to duplicate Long Lake in a phased manner, and expect to increase our synthetic crude oil production to 120,000 bbls/d over the next ten years. At Syncrude, the Stage 3 expansion is almost complete and we expect our share of production capacity there to increase by 8,000 bbls/d in 2006. Our capital program is also delivering results that will add to our future growth. In the Gulf of Mexico, we made a discovery at Knotty Head, our first sub-salt discovery and the deepest well ever drilled in the Gulf. We are presently drilling a sidetrack well to determine the extent of our discovery. Offshore Nigeria, we had further drilling success at Usan on Block OPL-222 and expect to book proved reserves once the project is sanctioned. In Canada, we are moving forward with commercial development of our coal bed methane resources and are looking to increase recovery rates from our heavy oil properties through the innovative use of technology. New production from Block 51 in Yemen and Scott and Telford in the UK North Sea offset natural declines on our base producing assets in Canada, the Gulf of Mexico and at Masila in Yemen. We sold more than 18,000 boe/d of Canadian conventional production and lost approximately 6,000 boe/d of Gulf of Mexico production as a result of hurricanes. While damage to most of our facilities was fairly minor, post-hurricane start-up delays caused by damage to surrounding infrastructure required some of our production to be shut-in for an extended period. Most of our fields in the Gulf are now up and running at full production. In 2005, our stock price increased from $24.35 to $55.42 per share, increasing shareholder value by more than $8 billion. It also increased our expense for employee stock-based compensation programs, and we expensed $490 million during the year. In 2005, Nexen was the 7th best performing stock among companies on the S&P TSX Composite Index. Following our 2004 North Sea acquisition, we purchased WTI put options to provide an annual average floor price of US$43/bbl and US$38/bbl on 60,000 bbls/d of production in 2005 and 2006, respectively. At the end of 2004, these put options had a market value of $200 million. As a result of continued strong crude oil prices, the value of these options was only $4 million at the end of 2005. We expensed the $196 million decrease in value in 2005. Throughout 2005, the Canadian dollar strengthened relative to the US dollar. Our sales revenue is denominated in or referenced to US dollars. As a result, our revenues decline as the US dollar weakens. On the other hand, our US-dollar capital spending, operating costs and US-dollar denominated debt are lower when 25 translated to Canadian dollars. Overall, the weaker US dollar reduced our 2005 cash flow from operating activities and net income by $251 million and $116 million, respectively, and debt decreased by $109 million. During 2005, our proved oil and gas and Syncrude reserves additions replaced the majority of our 2005 oil and gas and Syncrude production as shown in the following table: ------------------------------------------------------------------------------ Before After (mmboe) Royalties Royalties ------------------------------------------------------------------------------ Production ------------------------------------------------------------------------------ Oil and Gas 84 57 ------------------------------------------------------------------------------ Syncrude 6 6 ------------------------------------------------------------------------------ 90 63 ------------------------------------------------------------------------------ Additions ------------------------------------------------------------------------------ Oil and Gas 59 41 ------------------------------------------------------------------------------ Syncrude 23 15 ------------------------------------------------------------------------------ 82 56 ------------------------------------------------------------------------------ Our major development activities, principally at Buzzard and Syncrude, contributed 45 mmboe of the additions (36 mmboe after royalties). Reserves were also added from ongoing exploitation in Yemen, Canada, the Gulf of Mexico and the North Sea. Similar to last year, SEC regulations that require us to recognize bitumen reserves using year-end prices did not allow us to book any proved bitumen reserves for Long Lake because of high natural gas costs and wide light/heavy differentials. We also sold 49 mmboe of proved reserves (41 mmboe after royalties) in Canada during the year. In 2006, we are planning our largest capital program ever. We expect to invest $2.9 billion to develop core assets and develop and explore for new growth opportunities. Almost half of this capital will be directed toward major development projects at Buzzard, Long Lake and Syncrude, as well as the development of coal bed methane from the Upper Mannville coals in the Fort Assiniboine area of Alberta. On the exploration front, we will continue to appraise our Knotty Head discovery and expect to drill 20 high-impact wells primarily in the Gulf of Mexico, North Sea, offshore West Africa and Yemen. We expect our 2006 production to average between 220,000 boe/d and 240,000 boe/d, before royalties, and between 165,000 boe/d and 180,000 boe/d after royalties. In 2007, we expect our before-royalties production to grow to between 300,000 boe/d and 350,000 boe/d. Most of our new production is subject to little or no royalties and generates significantly higher margins than our current production. CAPITAL INVESTMENT ------------------------------------------------------------------------------- (Cdn$ millions) Estimated 2006 2005 2004 ------------------------------------------------------------------------------- Major Development 1,300 1,550 663 ------------------------------------------------------------------------------- Early Stage Development 300 54 19 ------------------------------------------------------------------------------- New Growth Exploration 600 456 266 ------------------------------------------------------------------------------- Core Asset Development 600 504 634 ------------------------------------------------------------------------------- 2,800 2,564 1,582 ------------------------------------------------------------------------------- Acquisitions - 20 2,587 ------------------------------------------------------------------------------- Total Oil & Gas and Syncrude 2,800 2,584 4,169 ------------------------------------------------------------------------------- Marketing, Corporate, Chemicals and Other 100 54 95 ------------------------------------------------------------------------------- Total Capital 2,900 2,638 4,264 ------------------------------------------------------------------------------- Our strategy and capital programs are focused on growing long-term value for shareholders. To maximize value, we invest in: o core assets for short-term production and free cash flow to fund capital programs and repay debt; o development projects that convert our discoveries into new production and cash flow; and o exploration projects for longer-term growth. As conventional basins in North America mature, we have been transitioning our operations toward less mature basins and unconventional resources. Our key focus areas include the North Sea, Athabasca oil sands, Canadian coal bed methane, Gulf of Mexico, offshore West Africa and the Middle East--areas we believe have attractive fiscal terms and significant remaining opportunity, and where we have some competitive advantage. In 2005, we invested more than $2.6 billion in capital expenditures, mostly in multi-year development projects and long cycle-time exploration. In 2006, we are managing our largest development and exploration program ever. We plan to invest more than $2.9 billion in our oil and gas and Syncrude assets. About 45% of this is focused on multi-year development projects, 24% on core assets to sustain production and provide cash flow, and 21% on drilling high-impact exploration wells and building our acreage position. The rest will be spent on early stage development activities.
2005 INVESTMENT PROGRAM ---------------------------------------------------------------------------------------------------------------- (Cdn$ millions) New Major Early Stage Growth Core Asset Development Development Exploration Development Total ---------------------------------------------------------------------------------------------------------------- Oil and Gas ---------------------------------------------------------------------------------------------------------------- Synthetic (mainly Long Lake) 743 31 16 - 790 ---------------------------------------------------------------------------------------------------------------- North Sea 469 10 59 87 625 ---------------------------------------------------------------------------------------------------------------- Yemen 161 - 41 75 277 ---------------------------------------------------------------------------------------------------------------- United States 4 - 211 144 359 ---------------------------------------------------------------------------------------------------------------- Canada 33 10 74 130 247 ---------------------------------------------------------------------------------------------------------------- Other Countries - 3 55 11 69 ---------------------------------------------------------------------------------------------------------------- Syncrude 140 - - 57 197 ---------------------------------------------------------------------------------------------------------------- 1,550 54 456 504 2,564 ---------------------------------------------------------------------------------------------------------------- Chemicals - - - 14 14 ---------------------------------------------------------------------------------------------------------------- Marketing, Corporate and Other - - - 40 40 ---------------------------------------------------------------------------------------------------------------- Total Capital 1,550 54 456 558 2,618 ---------------------------------------------------------------------------------------------------------------- As a % of Total Capital 59% 2% 17% 22% 100% ---------------------------------------------------------------------------------------------------------------- 2006 ESTIMATED CAPITAL ---------------------------------------------------------------------------------------------------------------- (Cdn$ millions) New Major Early Stage Growth Core Asset Development Development Exploration Development Total ---------------------------------------------------------------------------------------------------------------- Oil and Gas ---------------------------------------------------------------------------------------------------------------- Synthetic (mainly Long Lake) 650 100 - 10 760 ---------------------------------------------------------------------------------------------------------------- North Sea 450 100 75 85 710 ---------------------------------------------------------------------------------------------------------------- Yemen - - 35 160 195 ---------------------------------------------------------------------------------------------------------------- United States - 20 255 235 510 ---------------------------------------------------------------------------------------------------------------- Canada 150 60 120 80 410 ---------------------------------------------------------------------------------------------------------------- Other Countries - 20 115 - 135 ---------------------------------------------------------------------------------------------------------------- Syncrude 50 - - 30 80 ---------------------------------------------------------------------------------------------------------------- 1,300 300 600 600 2,800 ---------------------------------------------------------------------------------------------------------------- Marketing, Corporate and Other - - - 100 100 ---------------------------------------------------------------------------------------------------------------- Total Capital 1,300 300 600 700 2,900 ---------------------------------------------------------------------------------------------------------------- As a % of Total Capital 45% 10% 21% 24% 100% ----------------------------------------------------------------------------------------------------------------
MAJOR AND EARLY STAGE DEVELOPMENT PROJECTS More than 60% of our 2005 capital investment was directed toward early stage and major development projects including Buzzard, Long Lake, Syncrude Stage 3, Yemen Block 51 and CBM. These projects are characterized by multi-year investments that result in timing differences between reserve additions and capital expenditures, but each project has attractive full-cycle finding and development costs. Our new growth development resulted in proved reserve additions of 45 mmboe. SYNTHETIC We invested $774 million to develop our insitu oil sands resource in 2005, $743 million of this at Long Lake. The base Long Lake project remains on schedule and on budget. Detailed project engineering is substantially complete, and approximately 69% of the project's total costs have been committed. Steam injection is expected to begin in late 2006, followed by a ramp-up in bitumen production. The upgrader is scheduled to start operations in the second half of 2007. To enhance reliability, ensuring bitumen feedstock supply and building capacity for future growth, we are expanding our steam generating facilities so we can operate at a steam-oil ratio of up to 3.3 compared with the existing design of 2.5. This expansion is expected to cost up to $250 million ($125 million, net to 27 us). In optimizing the value from the project, we will also construct a facility to concentrate soot produced by the gasifier and thereby reduce disposal costs. This facility is expected to cost approximately $110 million ($55 million, net to us). These two projects will increase our total capital investment to construct Long Lake by 10% to $1.9 billion. At peak rates of premium synthetic crude, Long Lake Phase 1 should provide us with cash flow of between $400 million and $500 million per year, assuming oil prices of US$50/bbl (WTI). We are planning to increase synthetic crude oil production to 240,000 bbls/d over the next 10 years (120,000 bbls/d, net to us) in phases of 60,000 bbls/d (30,000 bbls/d, net to us) using the same technology as Long Lake. Phase 2 bitumen production is expected to begin in late 2010, with upgrader commissioning in 2011. In 2005, we invested $31 million to further evaluate our existing resource and acquire additional resource. We have made commitments for some of the long-lead time modules for phase 2. In 2006, we expect to invest $650 million on the ongoing development of Long Lake and $100 million in additional drilling and seismic to develop our oil sands leases and advance our regulatory applications. NORTH SEA -- BUZZARD At Buzzard, we invested $439 million in 2005. Buzzard is progressing on schedule and on budget. Development of the facilities is approximately 88% complete. We are currently drilling the production wells and expect to install the utilities and production decks during the second quarter of 2006. First oil is expected in late 2006. At its peak, Buzzard is expected to add approximately 85,000 boe/d of net production and between $1.6 billion and $1.7 billion of annual pre-tax cash flow, assuming US$50/bbl (WTI). In 2006, we expect to spend $450 million on Buzzard and $100 million to complete appraisal and development evaluation work on a number of small discoveries in the North Sea. YEMEN In Yemen on Block 51, we began production in late 2004 using an early production system. In 2005, we invested $161 million to construct permanent production facilities and further develop the fields. The permanent facilities are expected to be fully commissioned in early 2006. CANADA - COAL BED METHANE In Canada, we are developing the first commercial CBM project in Mannville coals. In 2005, we invested $33 million in CBM development, and in 2006, we plan to spend $150 million to develop 115 gross (53 net) sections using single-leg and multiple-leg wells, and construct gas gathering and processing facilities. We expect our CBM production to be modest in 2006, with growth in 2007 and beyond as we dewater the reservoirs and expand our developments. We are targeting to add approximately 150 mmcf/d by 2011 from our CBM projects. We have more than 600 net sections of CBM lands. Syncrude - STAGE 3 EXPANSION We invested $140 million in 2005 for the Syncrude Stage 3 expansion. This project was approximately 98% complete at year end, with 65% of the new units completed and operating reliably throughout 2005. Commissioning of all remaining Stage 3 units is underway. The expansion is expected to be completed and fully on stream by mid year, adding approximately 8,000 bbls/d of production capacity, net to us. We expect to spend $50 million in 2006 to complete and commission the Stage 3 upgrader expansion. NEW GROWTH EXPLORATION We invested $456 million in exploration in 2005. Approximately $140 million of this was invested in land, seismic and other early stage exploration activities. The balance was invested to drill 20 high-impact exploration wells. This resulted in a number of exploration successes, including the potentially significant Knotty Head discovery in the Gulf of Mexico where we have a 25% interest. We also had smaller discoveries in the Gulf at Big Bend, Anduin and Wrigley. In total, we participated in approximately one-third of deep-water discoveries in the Gulf of Mexico in 2005. Offshore West Africa, we drilled two successful appraisal wells at Usan on Nigeria's OPL-222. Despite our exploration success, we only recognized 4 mmboe of proved reserves because of additional appraisal work required to make a decision on commercial development. Knotty Head is a potentially significant discovery on Green Canyon Block 512. A sidetrack appraisal well commenced drilling in late 2005 and is nearing completion. Additional appraisal drilling is planned within the next year to determine the extent of the discovery. We are proceeding with development of the Wrigley discovery on Mississippi Canyon 506. We plan to sub-sea tieback the well to nearby infrastructure, with first production expected in the second half of 2006. We plan to complete our Big Bend discovery and tie back to existing infrastructure in 2007. At our Anduin discovery, we plan to drill an appraisal well in 2006 to determine the resource size and development options. Internationally, we drilled three small discoveries in the North Sea at Polecat, Yeoman and Black Horse. Their ultimate development is being evaluated and may depend on additional exploration success in the area. We have a 40% interest in Polecat, a 50% interest in Yeoman and a 60% interest in Black Horse, and we operate all three wells. 28 On Nigeria OPL-222, offshore West Africa, the Usan-7 and Usan-8 appraisal wells were successfully drilled during 2005. Appraisal of the Usan field is now complete and a preliminary field development plan has been submitted to Nigerian governmental agencies for approval. Preparation for basic engineering and tendering of contracts is proceeding on a multi-well development plan. The current design consists of a purpose-built floating production, storage and offshore loading facility (FPSO) capable of handling peak production rates of 160,000 bbls/d with storage capacity of 2 million barrels. Following government approvals of the final field development plan, the partners expect to formally sanction the project in late 2006. In 2005, we completed drilling the deep-water Efere well. This well was unsuccessful and its capital costs have been expensed. During 2006, the exploration and appraisal program outside the Usan field will continue on the block. In 2006, we expect to invest $600 million in exploration capital to drill 20 high-impact wells primarily in the Gulf of Mexico, the North Sea, offshore West Africa and Yemen. We currently have drilling rigs secured for the majority of our 2006 program. We have an extensive inventory of exploration prospects in the Gulf of Mexico. To ensure the continuity of our deep-water drilling program, we have contracted a new-build fifth-generation dynamically-positioned semi-submersible drilling rig, which is scheduled to be completed in 2009. The contract provides us access to the rig for two years over a three-and-a-half-year period. CORE ASSET DEVELOPMENT In 2005, we invested $504 million in core asset development and minor property acquisitions that added 33 mmboe of proved reserves. Our strategy is to maximize the value we extract from our core assets, in addition to adding reserves and production. In 2006, we plan to invest $600 million in our core assets including gas opportunities in the Eugene Island and Vermillion areas in the shallow-water Gulf of Mexico shelf, development activities at Scott and Telford in the North Sea and development of our BAK-A and BAK-B fields in Block 51, Yemen. 29 FINANCIAL RESULTS
YEAR-TO-YEAR CHANGE IN NET INCOME ------------------------------------------------------------------------------------------------------------ MD&A PAGE (Cdn$ 2005 vs 2004 2004 vs 2003 REFERENCE millions) ------------------------------------------------------------------------------------------------------------ Net Income for 2004 and 2003 (1) 793 578 ------------------------------------------------------------------------------------------------------------ Favourable (unfavourable) variances: ------------------------------------------------------------------------------------------------------------ Cash Items ------------------------------------------------------------------------------------------------------------ Production Volumes, After Royalties ------------------------------------------------------------------------------------------------------------ Crude Oil 39 (116) ------------------------------------------------------------------------------------------------------------ Natural Gas (55) (8) ------------------------------------------------------------------------------------------------------------ Change in Crude Oil Inventory 4 40 ------------------------------------------------------------------------------------------------------------ Total Volume Variance (12) (84) page 31 ------------------------------------------------------------------------------------------------------------ Realized Commodity Prices ------------------------------------------------------------------------------------------------------------ Crude Oil 648 365 ------------------------------------------------------------------------------------------------------------ Natural Gas 165 - ------------------------------------------------------------------------------------------------------------ Total Price Variance 813 365 page 34 ------------------------------------------------------------------------------------------------------------ Oil and Gas Operating Expense ------------------------------------------------------------------------------------------------------------ Conventional (64) (55) ------------------------------------------------------------------------------------------------------------ Synthetic (27) (2) ------------------------------------------------------------------------------------------------------------ Total Operating Expense Variance (91) (57) page 36 ------------------------------------------------------------------------------------------------------------ Marketing Contribution 49 (14) page 41 ------------------------------------------------------------------------------------------------------------ Chemicals Contribution 31 10 page 43 ------------------------------------------------------------------------------------------------------------ General and Administrative (96) (30) page 44 ------------------------------------------------------------------------------------------------------------ General and Administrative--Stock-Based Compensation Paid (60) (9) ------------------------------------------------------------------------------------------------------------ Interest Expense 46 26 page 45 ------------------------------------------------------------------------------------------------------------ Current Income Taxes (91) (38) page 45 ------------------------------------------------------------------------------------------------------------ Other (69) (22) ------------------------------------------------------------------------------------------------------------ Total Cash Variance 520 147 ------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------ Non-Cash Items ------------------------------------------------------------------------------------------------------------ Depreciation, Depletion, Amortization and Impairment page 37 ------------------------------------------------------------------------------------------------------------ Oil & Gas and Syncrude (308) 271 ------------------------------------------------------------------------------------------------------------ Other (19) 13 ------------------------------------------------------------------------------------------------------------ Exploration Expense (5) (45) page 38 ------------------------------------------------------------------------------------------------------------ General and Administrative--Stock-Based Compensation Accrual (337) (70) page 44 ------------------------------------------------------------------------------------------------------------ Future Income Taxes 348 (176) page 45 ------------------------------------------------------------------------------------------------------------ Increase (Decrease) in Fair Value of Crude Oil Put Options (252) 56 page 46 ------------------------------------------------------------------------------------------------------------ Gains from Divestiture Programs 418 - page 46 ------------------------------------------------------------------------------------------------------------ Other (6) 19 ------------------------------------------------------------------------------------------------------------ Total Non-Cash Variance (161) 68 ------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------ Net Income for 2005 and 2004 (1) 1,152 793 ------------------------------------------------------------------------------------------------------------
Note: 1 Includes results of discontinued operations (see Note 14 to our Consolidated Financial Statements). Significant variances in net income are explained in the sections that follow. The impact of foreign exchange on our operations is summarized on page 46. 30
OIL & GAS AND SYNCRUDE PRODUCTION --------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 --------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After Royalties (1) Royalties Royalties (1) Royalties Royalties (1) Royalties --------------------------------------------------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) --------------------------------------------------------------------------------------------------------------------------- Yemen 112.7 60.6 107.3 53.5 116.8 57.5 --------------------------------------------------------------------------------------------------------------------------- Canada (2) 29.2 22.6 36.2 28.2 46.3 35.4 --------------------------------------------------------------------------------------------------------------------------- United States 22.2 19.6 30.0 26.5 28.3 25.0 --------------------------------------------------------------------------------------------------------------------------- United Kingdom 12.6 12.6 1.5 1.5 - - --------------------------------------------------------------------------------------------------------------------------- Australia (3) - - 2.7 2.5 6.1 5.6 --------------------------------------------------------------------------------------------------------------------------- Other Countries 5.6 5.1 5.3 4.7 5.4 4.6 --------------------------------------------------------------------------------------------------------------------------- Syncrude (mbbls/d) (4) 15.5 15.3 17.2 16.6 15.3 15.2 --------------------------------------------------------------------------------------------------------------------------- 197.8 135.8 200.2 133.5 218.2 143.3 --------------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------------- Natural Gas (mmcf/d) --------------------------------------------------------------------------------------------------------------------------- Canada (2) 124 101 146 115 158 125 --------------------------------------------------------------------------------------------------------------------------- United States 116 99 148 126 145 122 --------------------------------------------------------------------------------------------------------------------------- United Kingdom 23 23 3 3 - - --------------------------------------------------------------------------------------------------------------------------- 263 223 297 244 303 247 --------------------------------------------------------------------------------------------------------------------------- Total (mboe/d) 242 173 250 174 269 185 ---------------------------------------------------------------------------------------------------------------------------
Notes: (1) We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. (2) Includes the following production from discontinued operations. See Note 14 to our Consolidated Financial Statements. -------------------------------------------------------------------------------- 2005 2004 2003 -------------------------------------------------------------------------------- Before Royalties -------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) 6.7 11.7 19.6 -------------------------------------------------------------------------------- Natural Gas (mmcf/d) 24 47 50 -------------------------------------------------------------------------------- After Royalties -------------------------------------------------------------------------------- Oil and Liquids (mbbls/d) 5.3 9.0 14.5 -------------------------------------------------------------------------------- Natural Gas (mmcf/d) 17 33 34 -------------------------------------------------------------------------------- (3) Comprises production from discontinued operations. See Note 14 to our Consolidated Financial Statements. (4) Considered a mining operation for US reporting purposes. 2005 VS 2004--LOWER PRODUCTION DECREASED NET INCOME BY $12 MILLION Production before royalties declined 3% during the year, while production after royalties remained consistent with 2004 levels. New royalty-free production from the UK North Sea partially offset the sale of higher-royalty production from Canada. We sold Canadian production during the year to reduce debt used to fund our acquisition of offshore oil and gas assets in the North Sea. Production was lower as a result of hurricane activity in the Gulf of Mexico in the second half of the year. Removing the impact of the Canadian asset sales and the lost volumes attributable to Hurricanes Katrina and Rita, our 2005 production before royalties would have increased 3% from 2004. 31
The following table summarizes our production changes year over year: --------------------------------------------------------------------------------------------- (mboe/d) Before Royalties After Royalties --------------------------------------------------------------------------------------------- 2004 Production 250 174 --------------------------------------------------------------------------------------------- Canada--Disposition of Properties (9) (6) --------------------------------------------------------------------------------------------- Gulf of Mexico--Hurricane Related Downtime (6) (5) --------------------------------------------------------------------------------------------- 235 163 --------------------------------------------------------------------------------------------- Production changes --------------------------------------------------------------------------------------------- Block 51 in Yemen 25 16 --------------------------------------------------------------------------------------------- North Sea 14 14 --------------------------------------------------------------------------------------------- Masila Block in Yemen (18) (8) --------------------------------------------------------------------------------------------- Gulf of Mexico (7) (6) --------------------------------------------------------------------------------------------- Canada (2) (2) --------------------------------------------------------------------------------------------- Australia (3) (3) --------------------------------------------------------------------------------------------- Syncrude (2) (1) --------------------------------------------------------------------------------------------- 2005 Production 242 173 ---------------------------------------------------------------------------------------------
Future production increases are expected to come from Syncrude in 2006 and our North Sea Buzzard project in late 2006, along with Long Lake synthetic production in 2007. Production volumes discussed in this section represent our working interest before royalties. YEMEN Yemen production increased 5% from 2004 as we replaced maturing production from Masila with new production from Block 51. Masila production declined 18%. As the field nears the end of its contract term, we are strategically managing development capital to optimize recovery of remaining reserves. In 2005, we drilled 36 development wells compared with 73 wells in 2004. While new wells coming on stream are yielding strong production rates, we expect Masila to continue declining in the future. On Block 51, production from the East Al Hajr field averaged 25,600 bbls/d during the year. We have been operating from temporary facilities and expect to complete the permanent central processing facility in the first quarter of 2006. During the year, we drilled 20 development wells. We expect our share of total production from Yemen to average between 90,000 bbls/d and 100,000 bbls/d in 2006. CANADA In the third quarter, we sold conventional oil and gas properties in Alberta, British Columbia and Saskatchewan that were producing 18,300 boe/d. Production from our remaining natural gas and heavy oil properties declined marginally. In 2006, we are focusing our capital on drilling infill shallow gas wells, developing our coal bed methane projects and developing new technologies to increase heavy oil recovery. In 2006, we plan to drill more than 300 net wells on our properties and expect our Canadian production to average between 35,000 boe/d and 40,000 boe/d. GULF OF MEXICO Gulf of Mexico production declined 24%, or about 13,000 boe/d from 2004. The effects of Hurricanes Katrina and Rita reduced volumes by approximately 6,000 boe/d as a result of shut-in production and subsequent start-up delays following damage to our facilities and third-party infrastructure. We carry insurance which, subject to certain deductibles, we expect will cover property damage and business interruption up to defined limits. We expensed insurance-related costs of US$34 million as a result of the hurricanes. In the deep water, natural declines and increasing water-cuts at Aspen reduced volumes by 8,000 boe/d from 2004. We plan to drill another development well at Aspen in 2006 to tap potential unrecovered reserves. Strong production from development drilling on the shelf and an additional deep-water well at Gunnison partly offset the Aspen decline. A second development well was drilled at Gunnison and came on stream in January 2006. We plan to continue development drilling on our maturing shelf properties to maintain current production rates and tie-in our deep-water discoveries at Wrigley and Dawson Deep. We expect our Gulf production to average between 40,000 boe/d and 45,000 boe/d in 2006. 32 NORTH SEA The Scott and Telford fields acquired in December 2004 contributed a full year of production averaging 16,400 boe/d. Our North Sea production was impacted by two generator failures on the Scott platform in early May. We completed repair work and performed a major maintenance turnaround on the platform in the third quarter. The platform upgrades and infill drilling enabled us to increase production rates in the second half of the year. Our non-operated Farragon field came on stream in November and was producing 3,900 boe/d net to Nexen from two producing wells at year end. We expect Farragon to contribute between 3,000 boe/d and 4,000 boe/d to our production in 2006. Our Buzzard development project is on time and on budget, and we expect to begin producing from this field in late 2006. We expect our total year production from our North Sea assets, which were producing approximately 19,000 boe/d when we purchased them in late 2004, to average between 25,000 boe/d and 30,000 boe/d in 2006. OTHER COUNTRIES In 2005, we completed abandonment activities in Australia, which ceased production in late 2004. Production from the Guando field in Colombia was consistent with 2004, as we maintained rates with nine additional development wells. We expect to maintain production rates in Colombia in 2006. SYNCRUDE Syncrude production decreased 10% from 2004 as a result of maintenance and turnaround work on various units during 2005. In January, the delayed start-up of the LC finer and unscheduled repairs to a hydrogen plant limited the hydrotreating capacity for the first quarter. Production was reduced again later in the year for a scheduled 52-day turnaround of the vacuum distillation unit. We exited 2005 at 20,000 bbls/d (net to us) following completion of the turnarounds. Start-up of the Stage 3 expansion is expected to increase our production capacity by approximately 8,000 bbls/d in mid-2006, and we expect our share of total-year production from Syncrude to average between 20,000 bbls/d and 22,000 bbls/d. 2004 VS 2003--LOWER PRODUCTION DECREASED NET INCOME BY $84 MILLION Production after royalties decreased 6% from 2003, half of which was attributable to the sale of our non-core Canadian light oil properties in southeast Saskatchewan in August 2003. Production before royalties decreased 7%, caused by the sale of properties in August 2003 and declining base production from our maturing conventional assets in the shallow-water Gulf of Mexico, Masila in Yemen and our remaining Canadian properties. Delays in development drilling programs also contributed to reduced volumes in Yemen and in the shallow-water Gulf of Mexico. However, our deep-water Gulf of Mexico assets performed strongly, achieving record production at Aspen and Gunnison. This partially offset the declining volumes from our maturing conventional properties. In the fourth quarter of 2004, new volumes from our North Sea acquisition and initial production from Block 51 in Yemen offset reduced volumes from Australia, where we produced our final barrel in November 2004. Syncrude production increased 12% from 2003, achieving a new annual record despite maintenance shut-down of the LC finer at year end. 33
COMMODITY PRICES --------------------------------------------------------------------------------------------- 2005 2004 2003 --------------------------------------------------------------------------------------------- Crude Oil --------------------------------------------------------------------------------------------- West Texas Intermediate (US$/bbl) 56.58 41.40 31.04 --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Differentials (1) (US$/bbl) --------------------------------------------------------------------------------------------- Heavy Oil - LLK 20.82 13.53 8.63 --------------------------------------------------------------------------------------------- MARS 6.59 6.15 3.53 --------------------------------------------------------------------------------------------- Masila 5.71 4.84 3.03 --------------------------------------------------------------------------------------------- Dated Brent 2.20 - - --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Producing Assets (Cdn$/bbl) --------------------------------------------------------------------------------------------- Yemen 62.07 47.59 39.45 --------------------------------------------------------------------------------------------- Canada 40.51 36.60 32.37 --------------------------------------------------------------------------------------------- United States 57.63 46.60 37.68 --------------------------------------------------------------------------------------------- United Kingdom 60.55 46.81 - --------------------------------------------------------------------------------------------- Australia - 51.22 43.14 --------------------------------------------------------------------------------------------- Other Countries 59.96 43.07 38.22 --------------------------------------------------------------------------------------------- Syncrude 71.00 52.80 43.36 --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Corporate Average (Cdn$/bbl) 58.98 45.90 38.04 --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Natural Gas --------------------------------------------------------------------------------------------- New York Mercantile Exchange (US$/mmbtu) 8.99 6.19 5.60 --------------------------------------------------------------------------------------------- AECO (Cdn$/mcf) 8.04 6.44 6.35 --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Producing Assets (Cdn$/mcf) --------------------------------------------------------------------------------------------- Canada 7.51 5.76 5.64 --------------------------------------------------------------------------------------------- United States 10.56 7.89 8.16 --------------------------------------------------------------------------------------------- United Kingdom 7.86 8.28 - --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Corporate Average (Cdn$/mcf) 8.89 6.85 6.85 --------------------------------------------------------------------------------------------- Nexen's Average Realized Oil and Gas Price (Cdn$/boe) 57.97 44.94 38.63 --------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------- Average Foreign Exchange Rate --------------------------------------------------------------------------------------------- Canadian to US Dollar 0.8253 0.7683 0.7135 ---------------------------------------------------------------------------------------------
Note: 1 These differentials are a discount to WTI. 2005 VS 2004--HIGHER REALIZED PRICES ADDED $813 MILLION TO NET INCOME WTI reached record highs in 2005 averaging US$56.58/bbl, an increase of 37% compared with US$41.40/bbl in 2004. We realized record annual prices for our crude oil, averaging $58.98/bbl in 2005, an increase of 28% over 2004. Although crude oil reference prices increased 37% over 2004, our realized prices only increased by 28%, because of wider crude oil differentials and a weaker US dollar. Our realized gas price increased 30% from a year ago to average $8.89/mcf. NYMEX increased 45% in the same period, averaging US$8.99/mmbtu. The full benefit of higher benchmark prices wasn't reflected in our realized prices because of the weaker US dollar in 2005. All of our oil sales and most of our gas sales are denominated in, or referenced to, US dollars. As a result, the weaker US dollar decreased net sales for the year by approximately $270 million, and reduced our realized crude oil and natural gas prices by approximately $4.40/bbl and $0.65/mcf, respectively, compared with 2004. 34 CRUDE OIL REFERENCE PRICES Crude oil prices remained strong in 2005 reaching new highs and new levels of volatility. WTI prices peaked on August 31 when trading broke through US$70/bbl. The trading range for WTI in 2005 was between US$41.25 and US$70.85. While global demand was moderate and supply levels adequate, the stability and security of long-term supply remained a concern, along with tightening refining capacity worldwide. Throughout the year, events that threatened supply or strained refining capacity caused prices to spike. Several factors contributed to increased prices and greater market volatility throughout the year: o hurricane activity in the US Gulf of Mexico removed approximately 110 million barrels of supply and temporarily shut down refining capacity; o growing participation by hedge funds and banks in the commodity markets; o ongoing labour and political unrest in crude oil producing regions, particularly the Middle East, West Africa and Venezuela; o political disputes or disagreements between producing and consuming regions; and o the weaker US dollar. With sufficient levels of supply and moderate demand, crude oil inventories, particularly in North America, are at the top of their historical range and almost 30 million barrels higher than last year. Given the shortage in refining capacity, product inventories, unlike crude oil inventories, have remained tight throughout most of the year. Most worldwide refining capacity requires light-sweet crude oil as feedstock, but only a small portion of new supply is light or sweet. With light-sweet crudes in greatest demand but limited supply, prices for both WTI and Brent have risen. Events that threatened this supply or refining capacity created volatility. CRUDE OIL DIFFERENTIALS Crude oil differentials widened in 2005 because of a strong WTI and greater demand worldwide for light-sweet crude oil than for heavy sour crude. World supply of heavy oil has been increasing faster than the supply of light crude, and refining constraints and environmental standards continue to tighten in favour of lighter crudes. Therefore, we expect differentials between light and heavy oil to remain wide. In Canada, heavy crude oil had some short-lived strength during the summer, but generally differentials widened in 2005, with benchmark LLK differentials averaging US$20.82. Differentials narrowed in the summer, as demand for heavy blends increased relative to light blends, reflecting normal summer demand for asphalt. Hurricane activity kept differentials narrow for longer than normal, as much of the heavy oil production from the Gulf to the US mid-continent was shut-in, increasing the demand for Canadian heavy oil. The heavy differential has since widened again, and we expect it to remain wide into 2007, when additional conversion capacity will enable more heavy oil. Our US Gulf Coast MARS differential widened slightly in relation to 2004, averaging US$6.59/bbl in 2005. While the differential strengthened during the year because of growing demand from US-based refiners, it did not outpace WTI, resulting in a slightly wider differential. With refineries damaged by hurricanes, there was a temporary decline in demand that caused the MARS differential to widen to US$15. Late in the year, the differential narrowed to normal levels with the recovery of demand from refiners. The Masila differential widened relative to WTI during 2005, averaging US$5.71/bbl compared with US$4.84/bbl in 2004. Despite an increase in demand from Asia and North America for sweeter blends, the differential still widened as a result of strong WTI pricing throughout 2005. The Brent/WTI differential strengthened during 2005, averaging US$2.20/bbl, resulting in a solid crude oil price for our North Sea production. Strong demand from European refiners, an increase in Asian demand and lost production in the North Sea combined to push Brent up relative to the North American WTI benchmark. NATURAL GAS REFERENCE PRICES Natural gas prices averaged US$8.99/mmbtu, reaching record highs and experienced increased volatility. Prices early in the year were propped up by strong oil prices. The disruptions caused by the hurricanes pushed North American gas prices to new highs. The volatility did not end with the hurricane activity, but continued into the winter, as markets speculated on the impact of a cold or mild winter on tight supply. Prices peaked on December 13, with NYMEX gas settling at US$15.38/mmbtu. Prices have since softened, mainly from a weak winter heating season and low inventory withdrawals. 35 2004 VS 2003--HIGHER REALIZED PRICES ADDED $365 MILLION TO NET INCOME Crude oil prices reached record levels in 2004, supported by supply concerns, high demand and speculative traders increasing volatility to all-time highs. The positive impact of strong crude oil reference prices was offset in part by the weakening US dollar and widening crude oil quality differentials. All of our oil sales and most of our gas sales are denominated in, or referenced to, US dollars. As a result, a stronger Canadian dollar relative to the US dollar reduced our realized crude oil price by $3.50/bbl and our realized natural gas price by $0.50/mcf. In total, our net sales decreased $220 million from 2003 because of the weakening US dollar. The Canadian to US dollar exchange rate closed the year at 83(cents).
OPERATING COSTS ------------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After (Cdn$/boe) Royalties (1) Royalties Royalties(1) Royalties Royalties(1) Royalties ------------------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------------------- Conventional Oil and Gas ------------------------------------------------------------------------------------------------------------------------------- Yemen 3.63 6.75 2.80 5.64 2.16 4.37 ------------------------------------------------------------------------------------------------------------------------------- Canada 8.21 10.34 7.12 8.98 6.00 7.76 ------------------------------------------------------------------------------------------------------------------------------- United States 6.35 7.33 5.30 6.12 4.49 5.19 ------------------------------------------------------------------------------------------------------------------------------- United Kingdom 14.90 14.90 8.26 8.26 - - ------------------------------------------------------------------------------------------------------------------------------- Australia - - 32.94 35.73 18.60 20.21 ------------------------------------------------------------------------------------------------------------------------------- Other Countries 5.55 6.08 3.76 4.09 7.47 9.01 ------------------------------------------------------------------------------------------------------------------------------- Average Conventional 6.03 8.70 5.13 7.59 4.17 6.24 ------------------------------------------------------------------------------------------------------------------------------- Synthetic Crude Oil ------------------------------------------------------------------------------------------------------------------------------- Syncrude 26.95 27.22 19.89 20.61 21.96 22.18 ------------------------------------------------------------------------------------------------------------------------------- Average Oil and Gas 7.36 10.34 6.15 8.83 5.19 7.56 -------------------------------------------------------------------------------------------------------------------------------
Note: (1) Operating costs per boe are our total oil and gas operating costs divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. 2005 VS 2004--HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME BY $91 MILLION Higher operating costs reflect the change in our profile as more of our production is coming from higher-cost areas such as the North Sea and from Canadian heavy oil following the Canadian property sales completed during the year. Operating costs were negatively impacted by storm-related costs and maintenance activities. In addition, high levels of industry activity and higher energy costs, driven by record commodity prices, have increased our operating costs. Our operations at Masila in Yemen are maturing and have higher operating costs, mainly from increased service rig activity to minimize production declines. These higher costs added 9(cents)/boe to our corporate average. Costs on a per-unit basis will continue to rise with increasing workover and water handling efforts and from declining production. Block 51 operating costs were higher than Masila, reflecting the use of temporary production facilities. Higher operating costs from Block 51 increased our corporate average by 53(cents)/boe. We expect operating costs at Block 51 to decrease in 2006 when we complete the permanent central processing facility early in the year. Industry cost pressures and the sale of conventional production increased our Canadian unit operating costs in 2005. Although we sold high-cost production relative to our corporate average, we expect our overall Canadian operating costs to increase as we will have proportionately higher production from our heavy oil properties. These properties have higher operating costs and lower recovery rates compared to the lighter oil production that was sold. We are focused on increasing recovery rates from our heavy oil properties by developing new technologies. In the Gulf of Mexico, lower volumes of higher-cost barrels at Aspen, along with $12 million of Aspen-1 intervention costs expensed in 2004, decreased our corporate average by 10(cents)/boe. Workovers on our shelf properties, coupled with lower production and property damage costs not covered by insurance, increased our corporate average by 5(cents)/boe from 2004. The addition of higher-cost North Sea production increased our corporate average unit costs by $1.14/boe. Our North Sea operating costs were higher than anticipated as a result of maintenance and repair work caused by generator failures in the second quarter and major maintenance turnaround and facilities upgrading at the Scott platform in the third quarter. We expect our North Sea operating costs to decrease on a per-unit basis in 2006. 36 Our Australian operations ceased in late 2004 and the exclusion of these high-cost, late-life barrels reduced our corporate average by 57(cents)/boe. US-dollar denominated operating costs were lower when translated to Canadian dollars as a result of the weak US dollar. Our corporate average was reduced by 30(cents)/boe as a result. Syncrude operating costs per boe were 35% higher than in 2004. Turnaround and maintenance costs accounted for half of the increase, as we completed major turnarounds on various upgrading units during the year. When combined with higher energy costs required in the upgrading process, our corporate average increased by 34(cents)/boe. In 2006, we expect operating costs per unit to increase. This reflects the higher proportion of Canadian heavy oil production in our production mix following the 2005 Canadian property sales, coupled with industry cost pressures in all of our operating areas. 2004 VS 2003--HIGHER OIL AND GAS OPERATING COSTS DECREASED NET INCOME BY $57 MILLION Our operating costs increased as a result of high-cost, late-life barrels in Australia, higher maintenance costs in Yemen and Canada, more workover and remediation activity in the Gulf of Mexico and the spread of fixed costs over fewer barrels. At Masila in Yemen, flow line replacements, higher water-handling costs and more maintenance increased our corporate unit operating costs by 30(cents)/boe. However, these increased costs in Yemen only reduced our corporate netbacks by 5(cents)/boe as a result of the cost recovery mechanism in our production sharing agreement. Operating costs in Canada were slightly lower than in 2003, but because of declining volumes, our corporate average unit costs increased by 25(cents)/boe. Aspen-1 intervention costs of $12 million were expensed in 2004. They were higher than expected, as storm activity in the Gulf of Mexico extended the work. These costs, together with higher workover activities in the shallow water, contributed a 28(cents)/boe increase to our corporate unit costs. The incremental North Sea barrels added 7(cents)/boe to our corporate average in 2004. Australia produced its final barrel in November 2004. These expensive late-life barrels increased our corporate unit costs by 30(cents)/boe, but high crude prices allowed us to produce them economically. The strength of the Canadian dollar reduced our US-dollar denominated operating costs, contributing a 25(cents)/boe reduction to our corporate unit costs. Syncrude's operating costs were flat compared to 2003, but because of increased volumes, unit costs decreased 9%. Higher natural gas input costs were offset by lower maintenance costs in 2004 since there were no major turnarounds. As more expensive Syncrude barrels were a larger portion of our total corporate production in 2004, our corporate unit operating costs increased by 17(cents)/boe.
DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A) ---------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ---------------------------------------------------------------------------------------------------------------------------- Before After Before After Before After (Cdn$/boe) Royalties (2) Royalties Royalties (2) Royalties Royalties (2) Royalties ---------------------------------------------------------------------------------------------------------------------------- Conventional Oil and Gas ---------------------------------------------------------------------------------------------------------------------------- Yemen 8.56 15.93 4.35 8.77 3.96 8.03 ---------------------------------------------------------------------------------------------------------------------------- Canada (1) 9.26 11.67 9.02 11.37 9.10 11.76 ---------------------------------------------------------------------------------------------------------------------------- United States 15.39 17.77 12.93 14.93 10.80 12.47 ---------------------------------------------------------------------------------------------------------------------------- United Kingdom 33.25 33.25 22.44 22.44 - - ---------------------------------------------------------------------------------------------------------------------------- Australia - - 5.82 6.31 13.31 14.46 ---------------------------------------------------------------------------------------------------------------------------- Other Countries 6.20 6.79 9.90 10.77 17.09 22.47 ---------------------------------------------------------------------------------------------------------------------------- Average Conventional 11.78 17.00 7.87 11.64 7.37 11.04 ---------------------------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------------------------- Synthetic Crude Oil ---------------------------------------------------------------------------------------------------------------------------- Syncrude 3.08 3.12 2.75 2.85 2.50 2.53 ---------------------------------------------------------------------------------------------------------------------------- Average Oil and Gas 11.23 15.77 7.52 10.80 7.09 10.33 ----------------------------------------------------------------------------------------------------------------------------
Notes: (1) 2003 DD&A per boe excludes the impairment charge described in Note 6 to the Consolidated Financial Statements. (2) DD&A per boe is our DD&A for oil and gas operations divided by our working interest production before royalties. We use production before royalties to monitor our performance consistent with other Canadian oil and gas companies. 37 2005 VS 2004--HIGHER OIL AND GAS DD&A DECREASED NET INCOME BY $308 MILLION Strong production volumes, new production from our North Sea assets and additional capital cost recovery from Block 51 in Yemen increased our oil and gas DD&A compared with 2004 levels. We also expensed $58 million related to unproved North Sea properties as a result of unsuccessful exploration activities. Block 51 production in Yemen increased our corporate unit depletion by $2.21/boe from 2004 as a result of carried interest accounting for the recovery of Block 51 capital costs. Strong production and higher realized oil prices have resulted in faster recovery of capital costs we paid on behalf of the government. Our Canadian depletion rate per unit has increased slightly compared with 2004. Reserve revisions at the end of 2004 increased our 2005 heavy oil depletion rate. This increase was somewhat offset when we stopped depleting our Canadian assets held for sale in the second quarter, but continued to recognize related production. The disposition of these assets in the third quarter changed our asset mix and reduced our average annual corporate depletion rate by 23(cents)/boe. Depletion rates in the Gulf of Mexico increased following reserve revisions in late 2004. Reduced volumes offset the increase in rates with minimal impact on our overall unit rate. North Sea depletion increased our corporate average by $2.37/boe in 2005. The depletable carrying costs of our Scott, Telford and Farragon fields include an allocation of the purchase price we paid for these assets. In addition, our North Sea depletion includes $58 million relating to a partial write-off of our purchase price allocation to unproved properties subject to unsuccessful exploration activities. The strengthening Canadian dollar offset these increases as the depletion of our international and US assets is denominated in US dollars. This lowered our corporate average by 70(cents)/boe compared with 2004. 2004 VS 2003--LOWER OIL AND GAS DD&A INCREASED NET INCOME BY $271 MILLION Our DD&A expense in 2003 included an impairment charge of $269 million, largely because of negative reserve revisions on our Canadian heavy oil properties. Excluding this charge from our 2003 per-unit DD&A costs, our per-unit corporate depletion rate has increased. Higher depletion from our more capital-intensive, deep-water properties in the Gulf of Mexico has increased corporate rates by 70(cents)/boe. However, these properties benefit from low royalties and lower unit operating costs, as most of the costs are capital in nature. Yemen increased our corporate rate by 30(cents)/boe mainly because additional volumes from Block 51 slightly offset lower Masila volumes. The new North Sea volumes increased our corporate rate by 20(cents)/boe. Our UK depletion rate of $22.44/boe reflects the depletion of part of the acquisition cost allocated to our interests in the Scott/Telford fields on a before-tax basis. Syncrude depletion rates increased reflecting the depletable costs of the Aurora 2 bitumen train, which came into service in late 2003. The strong Canadian dollar lowered our depletion rate by 45(cents)/boe, as the depletion of our US and international assets is denominated in US dollars. As well, the depletable costs on our Canadian heavy oil properties were reduced at year-end 2003, and both Australia and Nigeria were almost fully depleted. The writedown of our Canadian heavy oil properties reduced our depletion rate by 31(cents)/boe, and lower volumes in Canada, Australia and Nigeria contributed to a combined reduction of 65(cents)/boe.
EXPLORATION EXPENSE (1) -------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 -------------------------------------------------------------------------------------- Seismic 53 73 62 -------------------------------------------------------------------------------------- Unsuccessful Drilling 143 125 70 -------------------------------------------------------------------------------------- Other 55 48 69 -------------------------------------------------------------------------------------- Total Exploration Expense 251 246 201 -------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------- New Growth Exploration 456 266 267 -------------------------------------------------------------------------------------- Geological and Geophysical Costs 53 73 62 -------------------------------------------------------------------------------------- Total Exploration Expenditures 509 339 329 -------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------- Exploration Expense as a % of Exploration Expenditures 49% 73% 61% --------------------------------------------------------------------------------------
Note: (1) Includes exploration expense from discontinued operations. See Note 14 to our Consolidated Financial Statements. 38 2005 VS 2004--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $5 MILLION Our 2005 exploration program was our most active in company history, as we spent more than $500 million on 20 high-potential exploration wells in our key basins. In the Gulf of Mexico, Knotty Head, drilled to a depth of 34,189 feet, encountered hydrocarbons in multiple zones. We are continuing to appraise this discovery in 2006, initially by drilling a side-track well to further delineate the reservoir. Additional delineation in 2006 is contingent on finding a rig to continue our program here. Smaller successes in the Gulf of Mexico and the North Sea will be further evaluated in 2006. Drilling equipment has been contracted for the majority of this work. Our exploration expense includes costs associated with unsuccessful wells in the Gulf of Mexico, North Sea, offshore West Africa and Yemen. In the Gulf of Mexico, we expensed $44 million for the Vrede well. Vrede, a sub-salt prospect drilled to a total depth of 32,600 feet, encountered non-commerical quantities of hydrocarbons and was temporarily abandoned. We also wrote off costs relating to our Castleton dry hole together with trailing costs related to the 2004 Crested Butte, Wind River and Fawkes wells. In the North Sea, exploration expense includes costs relating to Black Horse, Polecat, Bennachie and Saracen. The Black Horse and Polecat wells encountered hydrocarbons, but insufficient to warrant stand-alone development. We will continue to evaluate these reservoirs in combination with other potential development projects that may be sanctioned in the future. Bennachie was abandoned after encountering no reservoir sands in the target zone. Saracen was written off earlier in the year as an unsuccessful exploratory well. Internationally, we expensed costs related to four unsuccessful wells on Block 51 in Yemen and we abandoned our deep-water Efere well in Nigeria, as well as our K-2 well on Block K in Equatorial Guinea. 2004 VS 2003--HIGHER EXPLORATION EXPENSE REDUCED NET INCOME BY $45 MILLION Higher exploration expense reflected the increase in our 2004 exploration capital expenditures. We had further success at Usan on Block OPL-222, offshore Nigeria, Block 51 in Yemen and at Dawson Deep, Tobago, Wrigley and Anduin in the deep-water Gulf of Mexico. However, unsuccessful drilling included dry holes in the Gulf of Mexico, offshore Nigeria, Equatorial Guinea, and in Yemen. In the Gulf of Mexico, we had five dry holes: Crested Butte, Main Pass 240, Shark, Fawkes and Wind River. At our 100%-owned Crested Butte well on Green Canyon Block 242, we found oil-bearing sands in many horizons, but the volumes were not commercial, so we abandoned the well. Further work is required to determine if a sidetrack is warranted. We expensed $39 million of costs for this well in the fourth quarter. We drilled Main Pass 240 and found the objective sand wet, so we abandoned the well in December 2004. Shark was an ultra-deep-shelf gas test on South Timbalier 174 that finished drilling during the first quarter of 2004. Following our evaluation, we expensed $25 million of well costs. Fawkes and Wind River completed drilling and were abandoned in early 2005, resulting in a write-off of $13 million in 2004. Overall, dry hole and seismic costs in the Gulf of Mexico accounted for more than 50% of our exploration expense. Dry hole costs also included the Ameena prospect on OML-115, offshore Nigeria, the Zorro-1 prospect, offshore Equatorial Guinea and two unsuccessful exploration wells on Block 51 in Yemen. 39 OIL & GAS AND SYNCRUDE NETBACKS Netbacks are the cash margins we receive for every equivalent barrel sold. The following table lists the sales prices, per-unit costs and netbacks for our producing assets, calculated using our working interest production before and after royalties.
BEFORE ROYALTIES ------------------------------------------------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US UK Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 62.07 42.42 60.26 57.83 59.96 71.00 57.97 ------------------------------------------------------------------------------------------------------------------- Royalties and Other (28.71) (8.75) (8.06) - (5.23) (0.71) (16.70) ------------------------------------------------------------------------------------------------------------------- Operating Expenses (3.63) (8.21) (6.35) (14.90) (5.55) (26.95) (7.36) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (7.17) - - - - - (3.34) ------------------------------------------------------------------------------------------------------------------- Cash Netback 22.56 25.46 45.85 42.93 49.18 43.34 30.57 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- 2004 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US Australia UK Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 47.59 35.76 46.94 51.22 47.45 43.07 52.80 44.94 ------------------------------------------------------------------------------------------------------------------- Royalties and Other (23.98) (7.40) (6.29) (4.00) - (3.49) (1.84) (13.65) ------------------------------------------------------------------------------------------------------------------- Operating Expenses (2.80) (7.12) (5.30) (32.94) (8.26) (3.76) (19.89) (7.36) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (5.82) - - - - - - (2.48) ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Cash Netback 14.99 21.24 35.35 14.28 39.19 35.82 31.07 22.66 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- 2003 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US Australia Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 39.45 32.99 42.88 43.14 38.22 43.36 38.63 ------------------------------------------------------------------------------------------------------------------- Royalties and Other (19.98) (7.53) (5.91) (3.44) (5.69) (0.48) (12.14) ------------------------------------------------------------------------------------------------------------------- Operating Expenses (2.16) (6.00) (4.49) (18.60) (7.47) (21.96) (5.19) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (4.73) - - - - - (2.06) ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Cash Netback 12.58 19.46 32.48 21.10 25.06 20.92 19.24 ------------------------------------------------------------------------------------------------------------------- AFTER ROYALTIES ------------------------------------------------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US UK Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 62.07 42.42 60.26 57.83 59.96 71.00 57.97 ------------------------------------------------------------------------------------------------------------------- Operating Expenses (6.75) (10.34) (7.33) (14.90) (6.08) (27.22) (10.34) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (13.35) - - - - - (4.69) ------------------------------------------------------------------------------------------------------------------- Cash Netback 41.97 32.08 52.93 42.93 53.88 43.78 42.94 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- 2004 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US Australia UK Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 47.59 35.76 46.94 51.22 47.45 43.07 52.80 44.94 ------------------------------------------------------------------------------------------------------------------- Operating Expenses (5.64) (8.98) (6.12) (35.73) (8.26) (4.09) (20.61) (8.83) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (11.72) - - - - - - (3.57) ------------------------------------------------------------------------------------------------------------------- Cash Netback 30.23 26.78 40.82 15.49 39.19 38.98 32.19 32.54 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- 2003 ------------------------------------------------------------------------------------------------------------------- ($/boe) Yemen Canada US Australia Other Syncrude Total ------------------------------------------------------------------------------------------------------------------- Sales 39.45 32.99 42.88 43.14 38.22 43.36 38.63 ------------------------------------------------------------------------------------------------------------------- Operating Expenses (4.37) (7.76) (5.19) (20.21) (9.01) (22.18) (7.56) ------------------------------------------------------------------------------------------------------------------- In-country Taxes (9.58) - - - - - (3.00) ------------------------------------------------------------------------------------------------------------------- Cash Netback 25.50 25.23 37.69 22.93 29.21 21.18 28.07 -------------------------------------------------------------------------------------------------------------------
40 OIL AND GAS MARKETING -------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 -------------------------------------------------------------------------------- Revenue 847 608 568 -------------------------------------------------------------------------------- Transportation (641) (451) (398) -------------------------------------------------------------------------------- Other (2) (2) (1) -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Net Marketing Revenue 204 155 169 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Marketing Contribution to Income from -------------------------------------------------------------------------------- Continuing Operations before Income Taxes 104 87 111 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Natural Gas -------------------------------------------------------------------------------- Physical Sales Volumes (1) (bcf/d) 4.9 4.9 3.3 -------------------------------------------------------------------------------- Transportation Capacity (bcf/d) 4.0 3.5 2.0 -------------------------------------------------------------------------------- Storage Capacity (bcf) 30 27 18 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Crude Oil -------------------------------------------------------------------------------- Physical Sales Volumes (1) (mbbls/d) 510 465 479 -------------------------------------------------------------------------------- Storage Capacity (mbbls) 580 408 - -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Value-at-Risk -------------------------------------------------------------------------------- Year-end 24 21 21 -------------------------------------------------------------------------------- High 28 42 31 -------------------------------------------------------------------------------- Low 11 17 14 -------------------------------------------------------------------------------- Average 21 29 20 -------------------------------------------------------------------------------- Note: (1) Excludes intra-segment transactions. 2005 VS 2004--NET MARKETING REVENUE INCREASED NET INCOME BY $49 MILLION Marketing delivered strong results in 2005, with net revenue of $204 million. Our gas marketing group grew their net revenue to $117 million. We achieved these results through our continued focus on an asset-based trading strategy, using our transportation and storage capacity to take advantage of seasonal and locational pricing differences and market inefficiencies. While 2005 was a profitable year, it was also volatile with hurricane activity in the Gulf of Mexico disrupting gas supply and infrastructure. This volatility caused us to recognize losses in the third quarter on financial contracts hedging our physical assets. However, we were able to recognize gains on our physical assets in the fourth quarter as we used our transportation capacity and sold gas from storage. This allowed us to recoup our third quarter losses and recognize $175 million of net revenue in the fourth quarter. We also generated profits from financial contracts that captured time and location spreads. Our crude oil marketing group contributed $65 million of net revenue in 2005, an increase of 33% over 2004. Similar to prior years, we continued to capitalize on forward prices, as well as differences in crude qualities. In particular, in 2005, we took advantage of contango (rising forward month prices) by successfully pricing our purchases lower than our sales, and by financially trading calendar spreads. We also captured profits around quality spreads by diverting crude oil, or by blending to enhance the crude quality, and attract higher prices. 2004 VS 2003--NET MARKETING REVENUE DECREASED NET INCOME BY $14 MILLION Marketing had another exceptional year in 2004 with net revenue of $155 million. Gas marketing contributed $95 million to net revenue from asset-based trading, our energy services business, and from transportation and commodity contracts acquired on favourable terms. During 2004, we took advantage of market inefficiencies and seasonal variations. In particular, our transportation and storage capacity gave us the flexibility to capitalize on weather events and move gas to where it was needed most. We also held financial contracts that enabled us to capture trading profits around time and location spreads. North American crude oil contributed $25 million to net revenue as varying degrees of backwardation (declining forward month prices) in the forward price curve throughout the year enabled us to capitalize on calendar spreads. In addition, we took advantage of quality spreads and arbitrage opportunities to capture favourable price differences. 41 International crude oil contributed $24 million, three times higher than in 2003. Throughout 2004, we successfully capitalized on the pricing of purchases relative to sales, as we took advantage of backwardation in the forward price curve. COMPOSITION OF NET MARKETING REVENUE ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 ------------------------------------------------------------------------------- Trading Activities 168 133 ------------------------------------------------------------------------------- Non-Trading Activities 36 22 ------------------------------------------------------------------------------- Total Net Marketing Revenue 204 155 ------------------------------------------------------------------------------- TRADING ACTIVITIES In marketing, we enter into contracts to purchase and sell crude oil and natural gas. We also use financial and derivative contracts, including futures, forwards, swaps and options for hedging and trading purposes. We account for all derivative contracts not designated as hedges for accounting purposes, using mark-to-market accounting, and record the net gain or loss from their revaluation in marketing and other income. The fair value of these instruments is included with accounts receivable or payable. They are classified as long-term or short-term based on their anticipated settlement date. We value derivative trading contracts daily using: o actively quoted markets such as the New York Mercantile Exchange and the International Petroleum Exchange; and o other external sources such as the Natural Gas Exchange, independent price publications and over-the-counter broker quotes. FAIR VALUE OF DERIVATIVE CONTRACTS At December 31, 2005, the fair value of our derivative contracts not designated as hedges totalled $169 million (2004--$93 million). Below is a breakdown of this fair value by valuation method and contract maturity.
--------------------------------------------------------------------------------------------------------------------- Maturity --------------------------------------------------------------------------------------------------------------------- less than more than (Cdn$ millions) 1 year 1-3 years 4-5 years 5 years Total --------------------------------------------------------------------------------------------------------------------- Prices --------------------------------------------------------------------------------------------------------------------- Actively Quoted Markets (29) 14 (18) (3) (36) --------------------------------------------------------------------------------------------------------------------- From Other External Sources 90 100 12 3 205 --------------------------------------------------------------------------------------------------------------------- Based on Models and Other Valuation Methods - - - - - --------------------------------------------------------------------------------------------------------------------- Total 61 114 (6) - 169 ---------------------------------------------------------------------------------------------------------------------
These unrealized fair values will be realized over time as the related contracts settle. Until then, the value of the contracts will vary with forward commodity prices. While forward prices vary, the value of our contracts only varies to the extent they are economically exposed or unprotected. As most of our unrealized value is not economically exposed, we expect to realize most of this fair value. More than 35% of the unrealized fair value relates to contracts that will settle in 2006. Contract maturities vary from a single day up to eight years. Those maturing beyond one year primarily relate to North American natural gas positions. The relatively short maturity of our contracts, the high quality of our valuations and the limited economic exposure combine to lower our portfolio risk. Included in the derivative contracts that we mark-to-market are financial contracts that act as economic hedges of our physical transportation and storage capacity. For economic purposes, we monitor the fair value of our transportation and storage capacity as well as any commodities we have in storage, but we do not record this value in income until realized. At the end of 2005, the unrecognized fair value of these transportation and storage positions was $29 million. We have designated certain derivative contracts as accounting cash flow hedges of the future sale of our gas in storage. Mark-to-market gains and losses on these designated contracts are excluded from income until the underlying inventory is sold. At December 31, 2005, we had $35 million of unrecognized losses on these derivative contracts. These contracts have been valued from actively quoted markets and will settle within 12 months. 42
CHANGES IN FAIR VALUE OF DERIVATIVE CONTRACTS -------------------------------------------------------------------------------------------------------------------------- Contracts Contracts (Cdn$ millions) Outstanding at Entered into Beginning of Year During Year Total -------------------------------------------------------------------------------------------------------------------------- Fair Value at December 31, 2004 93 - 93 -------------------------------------------------------------------------------------------------------------------------- Change in Fair Value of Contracts 92 90 182 -------------------------------------------------------------------------------------------------------------------------- Net Losses (Gains) on Contracts Closed (47) (59) (106) -------------------------------------------------------------------------------------------------------------------------- Changes in Valuation Techniques and Assumptions (1) - - - -------------------------------------------------------------------------------------------------------------------------- Fair Value at December 31, 2005 138 169 -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- Unrecognized Losses on Hedges of Future Sale of Gas Inventory at December 31, (35) 2005 -------------------------------------------------------------------------------------------------------------------------- Total Outstanding at December 31, 2005 134 --------------------------------------------------------------------------------------------------------------------------
Note: (1) Our valuation methodology has been applied consistently year-over-year.
TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS -------------------------------------------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 -------------------------------------------------------------------------------------------------------------------------- Current Assets 382 177 -------------------------------------------------------------------------------------------------------------------------- Non-Current Assets 232 91 -------------------------------------------------------------------------------------------------------------------------- Total Derivative Contract Assets 614 268 -------------------------------------------------------------------------------------------------------------------------- Current Liabilities 321 129 -------------------------------------------------------------------------------------------------------------------------- Non-Current Liabilities 124 46 -------------------------------------------------------------------------------------------------------------------------- Total Derivative Contract Liabilities 445 175 -------------------------------------------------------------------------------------------------------------------------- Total Derivative Contract Net Assets (1) 169 93 --------------------------------------------------------------------------------------------------------------------------
Note: (1) Excludes derivative contracts that have been designated as accounting hedges. NON-TRADING ACTIVITIES We enter into fee-for-service contracts related to transportation and storage of third-party oil and gas. We also earn income from our power generation facility. We earned $36 million from our non-trading activities in 2005 (2004--$22 million). In 2004 and 2005, we increased our transportation capacity and were paid to assume future obligations associated with the capacity. We have $28 million of deferred revenue on our balance sheet to recognize the liability associated with these obligations. We are amortizing this deferred revenue to earnings as the capacity is used.
CHEMICALS -------------------------------------------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 -------------------------------------------------------------------------------------------------------------------------- Net Sales 398 378 375 -------------------------------------------------------------------------------------------------------------------------- Sales Volumes (thousand short tons) -------------------------------------------------------------------------------------------------------------------------- Sodium Chlorate 493 506 478 -------------------------------------------------------------------------------------------------------------------------- Chlor-alkali 400 403 396 -------------------------------------------------------------------------------------------------------------------------- Operating Profit (1) 136 105 95 -------------------------------------------------------------------------------------------------------------------------- Operating Margin (2) 34% 28% 25% -------------------------------------------------------------------------------------------------------------------------- Chemicals Contribution to Income from Continuing Operations Before Income 37 40 28 Taxes -------------------------------------------------------------------------------------------------------------------------- Capacity Utilization 96% 95% 95% --------------------------------------------------------------------------------------------------------------------------
Notes: (1) Total revenues less operating costs, transportation and other. (2) Operating profit divided by net sales. 2005 VS 2004--HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME BY $31 MILLION In the third quarter of 2005, we monetized a portion of our chemicals business by creating the Canexus Income Fund through an initial public offering (IPO), which raised net proceeds of $301 million. Canexus Income Fund invested the offering proceeds into Canexus Limited Partnership, which also raised US$167 million ($200 million) of bank debt. Canexus Limited 43 Partnership used the proceeds from Canexus Income Fund's IPO and the bank debt, together with the issuance of 50.5 million exchangeable units of the Canexus Limited Partnership to Nexen, to purchase our chemicals operations. The exchangeable units we hold had a market value of $442 million at December 31, 2005. We have retained a 61.4% indirect interest in the chemicals operations through our investment in Canexus Limited Partnership, and we recorded a gain of $193 million on the dilution of our interest. Despite lower sales volumes, strong chlor-alkali prices and higher margins generated strong results for the chemicals business. Sodium chlorate volumes decreased compared with 2004 as a result of our decision in early 2005 to forego low-margin business consistent with our restructuring effort and the closure of our Amherstburg, Ontario plant. Sales and operations from the Brazil plant remained strong as a result of continued strong demand from Aracruz Cellulose, our primary customer in Brazil, and an expanded presence in the merchant market. The weaker US dollar put pressure on our US-dollar denominated sales, reducing net sales by $13 million. During 2005, we purchased US-dollar foreign currency call options to mitigate our exposure to the weakening dollar. We generated $4 million of income as a result of these call options. Our chemicals contribution was reduced by $12 million for an impairment charge relating to our chemicals plant in Amherstburg, which was closed in the third quarter of 2005. 2004 VS 2003--HIGHER CHEMICALS OPERATING PROFIT INCREASED NET INCOME BY $10 MILLION Our chemicals business benefited from strong demand for bleaching chemicals in North and South America. Solid North American demand for chlor-alkali and sodium chlorate throughout 2004 resulted in strong pricing for our products. However, a stronger Canadian dollar lowered our sales by $15 million in 2004, as most of our sales are denominated in US dollars, while our costs are primarily in Canadian dollars. We successfully completed the expansion of our plant in Brandon, Manitoba in October 2004, making it the largest sodium chlorate production facility in the world. This expansion minimizes our exposure to the rising electricity costs faced in other provinces, as Manitoba enjoys a stable, regulated electricity market. At our Brazil plant, production improvements enabled us to take advantage of strong market demand. CORPORATE EXPENSES GENERAL AND ADMINISTRATIVE (G&A) (1) ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------- General and Administrative Expense before ------------------------------------------------------------------------------- Stock Based Compensation 302 206 176 ------------------------------------------------------------------------------- Stock Based Compensation (2) 490 93 14 ------------------------------------------------------------------------------- Total General and Administrative Expense 792 299 190 ------------------------------------------------------------------------------- Notes: (1) Includes G&A from discontinued operations. See Note 14 to our Consolidated Financial Statements. (2) Includes tandem option plan, stock options for our US-based employees and stock appreciation rights. 2005 VS 2004--HIGHER COSTS REDUCED NET INCOME BY $493 MILLION Our stock-based compensation expense in 2005 reflects the significant increase in the price of our common shares. Our share price increased 128% from $24.35 to $55.42, adding more than $8 billion of shareholder value. The expense represents approximately 6% of the increase in shareholder value. Notwithstanding this increase in our share price, cash payments to employees under our stock-based compensation programs only amounted to $79 million. Our growing international presence and the expansion of our businesses increased our G&A costs during the year. Costs reflect more employees, additional travel, and higher compliance and governance costs, combined with increased variable incentive compensation stemming from our record results. We also incurred additional costs related to our disposition activities and the integration of our North Sea operations acquired in late 2004. 2004 VS 2003--HIGHER COSTS REDUCED NET INCOME BY $109 MILLION During the second quarter, our shareholders approved the modification of our stock option plan to a tandem option plan, creating a one-time G&A expense of $82 million. Other G&A costs include increased variable incentive compensation in light of our record results, more employees because of increased capital investment, and higher regulatory compliance costs, including those associated with our Sarbanes-Oxley project on internal control documentation. 44 INTEREST ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------- Interest (1) 275 194 212 ------------------------------------------------------------------------------- Less: Capitalized (178) (51) (43) ------------------------------------------------------------------------------- Net Interest Expense 97 143 169 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Effective Rate 6.4% 6.6% 7.2% ------------------------------------------------------------------------------- Note: (1) Includes dividends on preferred securities in 2004 and 2003. See Note 1(u) to our Consolidated Financial Statements. 2005 VS 2004--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $46 MILLION We acquired our North Sea assets in late 2004. We partially financed this acquisition with US$1 billion of new long-term debt, which increased our interest costs by $87 million in 2005. Interest expense also increased $3 million relating to the Canexus debt consolidated with our results. However, the stronger Canadian dollar lowered our US-dollar denominated interest by $12 million. During the last two years, we have taken advantage of declining interest rates by replacing our higher-cost preferred securities with new long-term debt at lower rates. We capitalize interest on our major development projects in the North Sea, Syncrude, Long Lake and Block 51 in Yemen based on our average borrowing rate. Capitalized interest grew primarily from the increased investment in the North Sea Buzzard project and additional spending at Long Lake. We expect capitalized interest to continue increasing as we invest additional capital on these projects prior to their completion in 2006 and 2007. 2004 VS 2003--LOWER NET INTEREST EXPENSE INCREASED NET INCOME BY $26 MILLION In late 2003 and early 2004, we refinanced our preferred securities with lower-cost debt. We also repaid US$225 million of bonds in February 2004. These two events reduced interest expense in 2004. In December 2004, we drew US$1.5 billion on our acquisition credit facilities to provide financing for our UK North Sea acquisition, increasing our interest expense by $5 million. The strong Canadian dollar lowered our US-dollar denominated interest expense by $6 million. Capitalized interest increased over 2003 from additional capital spending at our major development projects including Syncrude Stage 3 expansion and Long Lake in Canada, Block 51 in Yemen and Buzzard in the North Sea. INCOME TAXES ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------- Current 339 248 210 ------------------------------------------------------------------------------- Future (229) 119 (57) ------------------------------------------------------------------------------- Total Provision for Income Taxes 110 367 153 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Disclosed as: ------------------------------------------------------------------------------- Provision for Income Taxes--Continuing Operations 239 317 97 ------------------------------------------------------------------------------- Provision for Income Taxes--Discontinued Operations (1) (129) 50 56 ------------------------------------------------------------------------------- Total Provision for Income Taxes 110 367 153 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Effective Rate 9% 32% 21% ------------------------------------------------------------------------------- Note: (1) See Note 14 to our Consolidated Financial Statements. 2005 VS 2004--EFFECTIVE TAX RATE DECREASES FROM 32% TO 9% The recovery of future taxes payable of $229 million is attributable to the disposition of our oil and gas producing properties in Canada and the sale of our chemicals business to the Canexus Limited Partnership. As a result of the dispositions, we revalued our future income tax liabilities for the change in the underlying book and tax values. This revaluation resulted in the reduction of our future income tax liabilities. In addition, the disposition gains were taxed at lower capital gains tax rates. Removing the tax impact of the dispositions, the effective tax rate for our continuing operations was 32%. 45 In a recent pre-budget announcement, the UK government said it intends to increase the 10% supplemental charge on income from oil and gas activities to 20% effective January 1, 2006. This increase is subject to the introduction of legislation. If this announcement becomes law, we expect our effective tax rate to increase above 32%. Current income taxes include cash taxes in Yemen of $296 million (2004--$227 million; 2003--$201 million). Our current income tax provision also includes cash taxes in Colombia, federal and state taxes in the US and capital taxes in Canada. 2004 VS 2003--EFFECTIVE TAX RATE INCREASES FROM 21% TO 32% In 2004, a 1% reduction in Alberta's corporate income tax rate resulted in a $15 million recovery of future income taxes. The low effective tax rate for 2003 resulted from reduced federal tax rates for Canadian resource activities, which generated a recovery of future income taxes of $76 million. OTHER ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------- Gain on Dilution of Interest in Chemicals Business 193 - - ------------------------------------------------------------------------------- Gain on Disposition of Oil and Gas Asset included as Discontinued Operations 225 - - ------------------------------------------------------------------------------- Increase (Decrease) in Fair Value of Crude ------------------------------------------------------------------------------- Oil Put Options (196) 56 - ------------------------------------------------------------------------------- As a result of the sale of our chemicals business to the Canexus Limited Partnership, we recorded a gain on the dilution of our interest from 100% to 61.4% of $193 million. Our gain on the sale of Canadian oil and gas properties in Alberta, British Columbia and Saskatchewan was $225 million. This gain is net of losses attributable to pipeline contracts and fixed-price gas contracts associated with these properties that we retained, but no longer use in our oil and gas business. Following our North Sea acquisition in late 2004, we purchased put options on 60,000 bbls/d of oil production for 2005 and 2006 to ensure base cash flow in those years while we invest in our major development projects. These options created an average floor price for this production of US$43.17/bbl in 2005 and US$38.17/bbl in 2006. Accounting rules require that these options be recorded at fair value throughout their term. As a result, changes in forward crude oil prices cause gains or losses to be recorded on these options at each period end. A gain of $56 million was recorded in the fourth quarter of 2004, bringing the fair value of these options to $200 million. During 2005, a significant increase in forward crude prices resulted in a value loss of $196 million. The carrying value of these options at December 31, 2005 was $4 million. IMPACT OF FOREIGN EXCHANGE ON OPERATIONS The strengthening Canadian dollar relative to the US dollar reduced cash flow from operating activities by $251 million and our net income by $116 million. This is because our foreign revenues and realized commodity prices, referenced in US dollars, were lower when translated to Canadian dollars. However, we benefit to the extent that our foreign operating costs and capital expenditures are reduced when translated. In addition, most of our fixed-rate debt is denominated in US dollars so the Canadian dollar equivalent of this debt is reduced with a strengthening Canadian dollar. We have designated our US-dollar denominated debt as a hedge of our net investment in foreign operations. As a result, unrealized foreign exchange gains on the translation of this debt are not included in our net income, but are included as cumulative foreign currency translation adjustments on our balance sheet. The tax effect of unrealized foreign exchange gains on our US-dollar debt results in an increase to our future income tax liabilities, which is offset by a decrease to our cumulative translation adjustment account. OUTLOOK FOR 2006 In 2006, we plan to invest $2.9 billion in value-generating capital projects. Approximately 45% of this capital will be invested in major development projects. These include Buzzard, Long Lake, coal bed methane and Syncrude Stage 3, all planned to come on stream in 2006 and 2007. We are also directing 10% of our 2006 capital to early stage development projects expected to contribute production and cash flow beyond 2006. These include development of additional CBM lands, enhanced oil recovery projects, additional phases of oil sands and existing North Sea discoveries. We have allocated 21% of our capital to high-quality exploration opportunities in our growth areas. The remaining 24% of the 2006 capital will be invested to exploit potential in our existing producing assets and in other corporate assets. Details of our 2006 capital investment program are included in the Capital Investment section of the MD&A. 46 DAILY PRODUCTION Even after selling Canadian production in mid-2005, we expect our 2006 production before royalties to be similar to 2005. Our annual production for 2006 is expected to average between 220,000 boe/d and 240,000 boe/d before royalties, 165,000 boe/d and 180,000 boe/d after royalties, as follows: 2006 Estimated Production ------------------------------------------------------------------------------- Before After (mboe/d) Royalties Royalties ------------------------------------------------------------------------------- Gulf of Mexico 40 - 45 33 - 38 ------------------------------------------------------------------------------- North Sea 25 - 30 25 - 30 ------------------------------------------------------------------------------- Yemen 90 - 100 50 - 55 ------------------------------------------------------------------------------- Canada 35 - 40 27 - 31 ------------------------------------------------------------------------------- Syncrude 20 - 22 18 - 20 ------------------------------------------------------------------------------- Other International 6 - 7 5 - 6 ------------------------------------------------------------------------------- Total 220 - 240 165 - 180 ------------------------------------------------------------------------------- We expect our production will grow significantly in 2007, as we gain a full year of high-margin production from Buzzard and Syncrude Stage 3, and Long Lake synthetic volumes come on stream. Production after royalties is expected to increase by more than 50% in 2007, generating strong growth in our operating margins and cash flow, assuming commodity prices remain strong. CASH FLOW AND SENSITIVITIES We expect to generate more than $2.6 billion in cash flow from operating activities in 2006 (before site restoration and geological and geophysical expenditures), assuming the following: ------------------------------------------------------------------------------- WTI (US$/bbl) 55.00 ------------------------------------------------------------------------------- NYMEX Natural Gas (US$/mmbtu) 9.25 ------------------------------------------------------------------------------- US to Canadian Dollar Exchange Rate 0.85 ------------------------------------------------------------------------------- Changes in actual commodity prices and exchange rates impact our annual cash flow from operating activities as follows: ------------------------------------------------------------------------------- (Cdn$ millions) ------------------------------------------------------------------------------- WTI--US$1 Change 40 ------------------------------------------------------------------------------- NYMEX Natural Gas--US $0.10 Change 7 ------------------------------------------------------------------------------- Exchange Rate--$0.01 Change 25 ------------------------------------------------------------------------------- We expect our chemicals and marketing businesses to continue generating solid contributions to cash flow and net income in 2006. We continue to see strong demand and high prices for our chemical products. Solid North American energy markets are expected in 2006, which will enable our marketing group to profit from our asset-based trading strategy. Our marketing group plans to expand into European markets with the addition of crude oil volumes from Buzzard in the North Sea. 47 LIQUIDITY AND CAPITAL RESOURCES CAPITAL STRUCTURE ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 ------------------------------------------------------------------------------- Net Debt (1) ------------------------------------------------------------------------------- Bank Debt 171 1,993 ------------------------------------------------------------------------------- Public Senior Notes 2,980 1,813 ------------------------------------------------------------------------------- Senior Debt 3,151 3,806 ------------------------------------------------------------------------------- Subordinated Debt 536 553 ------------------------------------------------------------------------------- Total Debt 3,687 4,359 ------------------------------------------------------------------------------- Less: Cash and Cash Equivalents (48) (73) ------------------------------------------------------------------------------- Less: Restricted Cash (70) - ------------------------------------------------------------------------------- 3,569 4,286 ------------------------------------------------------------------------------- Less: Non-Cash Working Capital (2) 72 (67) ------------------------------------------------------------------------------- Total Net Debt 3,641 4,219 ------------------------------------------------------------------------------- Shareholders' Equity (3) 4,008 2,867 ------------------------------------------------------------------------------- Notes: (1) Includes all of our debt and is calculated as long-term debt less working capital. (2) Excludes short-term borrowings. (3) At January 31, 2006, there were 261,614,723 common shares and US$460 million of unsecured subordinated securities outstanding. These subordinated securities may be redeemed by issuing common shares at our option after November 8, 2008. The number of shares issuable depends on the common share price on the redemption date. NET DEBT We use net debt as a key indicator of our leverage and to monitor the strength of our balance sheet. Net debt is directly related to our operating cash flows, capital investment activities and disposition programs. We ended the year with net debt of $3.6 billion, a decrease of $0.6 billion from 2004. During the year, we sold certain Canadian oil and gas producing assets, monetized a portion of our chemicals business and issued more than US$1 billion of long-term debt. These funds were used to repay the acquisition credit facilities that we used to finance purchase of North Sea assets in late 2004, and to partially fund our 2005 investment program. Our cash flow from operating activities funded the balance of our investment program. The year-over-year change in our net debt results from: ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 ------------------------------------------------------------------------------- Capital Investments (including 2004 North Sea Acquisition) 2,638 4,264 ------------------------------------------------------------------------------- Cash Flow from Operating Activities (2,143) (1,606) ------------------------------------------------------------------------------- Excess of Capital Investment over Cash Flow 495 2,658 ------------------------------------------------------------------------------- Net Proceeds on Disposition of Oil and Gas Properties (911) (34) ------------------------------------------------------------------------------- Net Proceeds from Canexus Initial Public Offering (301) - ------------------------------------------------------------------------------- Dividends on Common Shares 52 52 ------------------------------------------------------------------------------- Issue of Common Shares (Primarily Exercise of Employee Stock Options) (58) (124) ------------------------------------------------------------------------------- Foreign Exchange Translation of US-dollar Debt and Cash (113) (78) ------------------------------------------------------------------------------- Increase in Current Obligation Related to Stock Based Compensation 321 91 ------------------------------------------------------------------------------- Other (63) (36) ------------------------------------------------------------------------------- Increase (Decrease) in Net Debt (578) 2,529 ------------------------------------------------------------------------------- 48 The decrease in our net debt has improved our net-debt-to-cash-flow leverage, while our lower interest coverage reflects the additional interest incurred to finance our North Sea acquisition, as follows: ------------------------------------------------------------------------------- (times) 2005 2004 2003 ------------------------------------------------------------------------------- Net Debt to Cash Flow from Operating Activities 1.7 2.6 1.2 ------------------------------------------------------------------------------- Interest Coverage (1) 9.8 11.9 10.1 ------------------------------------------------------------------------------- Note: (1) Earnings before interest, taxes, DD&A and exploration expense divided by interest expense (before capitalized interest). Our business strategy is focused on value-based growth through full-cycle exploration and development, supplemented by strategic acquisitions when appropriate. We have leveraged our balance sheet in the past to accomplish our growth strategy, as most of our projects have long-cycle times, requiring significant amounts of capital to be invested prior to generating cash flows. Historically, we have been successful with this strategy as we used leverage to: o develop the Masila project in Yemen in 1993; o acquire Wascana in 1997; o repurchased 20 million common shares in 2000; o acquire the remaining interest in Aspen in 2003; and o acquire the Buzzard project and other key assets in the North Sea in 2004. Each time, we exceeded our internal net debt to cash flow target band; however, we successfully brought our leverage down once these projects began generating cash flow. In 2005, we reduced our net debt by selling producing assets in Canada and monetizing a portion of our chemicals business. Our future liquidity is expected to strengthen and our net debt is expected to be reduced further when our Buzzard and Long Lake projects come on stream and contribute significant free cash flow in 2007 and beyond. CHANGE IN WORKING CAPITAL ------------------------------------------------------------------------------- Increase/ (Cdn$ millions) 2005 2004 (Decrease) ------------------------------------------------------------------------------- Cash and Cash Equivalents 48 73 (25) ------------------------------------------------------------------------------- Restricted Cash 70 - 70 ------------------------------------------------------------------------------- Accounts Receivable 3,151 2,100 1,051 ------------------------------------------------------------------------------- Inventories and Supplies 504 351 153 ------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities (3,710) (2,377) (1,333) ------------------------------------------------------------------------------- Other (17) (7) (10) ------------------------------------------------------------------------------- 46 140 (94) ------------------------------------------------------------------------------- Higher commodity prices impacted our non-cash working capital by increasing the receivables and payables attributable to our marketing group. Inventory held by our marketing operation was higher at year end from higher gas prices that increased the cost of our inventoried gas. Our payables have increased since 2004 because of the higher accrued liability of our stock-based compensation programs. LIQUIDITY We generally rely on operating cash flows to fund capital requirements and provide liquidity. We build our opportunity portfolio to provide a balance of short-term, mid-term, and longer-term growth. Given the long cycle-time of some of our development projects and the volatility of commodity prices, it is not unusual in any given year for capital expenditures to exceed our cash flow. When this happens, we draw on available credit facilities, as we maintain significant committed credit facilities. At December 31, 2005, we had committed term credit facilities of $2.4 billion that are available until 2010. At year end, $250 million of these facilities were utilized to support letters of credit. We also had $732 million of uncommitted, unsecured credit facilities, of which $468 million was utilized to support letters of credit. From time to time, we access the capital markets to meet our financing needs. We also use various financial instruments to minimize our exposure to fluctuations in foreign exchange and commodity prices. For example, we purchased WTI put options for 2005 and 2006 to mitigate liquidity risk and reduce cash flow volatility. Overall, we manage our capital structure to maintain flexibility so we can fund our capital programs throughout the highs and lows of the price cycles inherent in the oil and gas business. 49 The table on the following page shows how we use our cash flow from operating activities to fund our investing activities. When our operating cash flows exceed our investment requirements, we generally pay down debt. We borrow or issue equity to fund investment requirements that exceed our operating cash flow.
-------------------------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 2002 2001 -------------------------------------------------------------------------------------------------------- Cash Flow from Operating Activities 2,143 1,606 1,405 1,250 1,496 -------------------------------------------------------------------------------------------------------- Cash Flow from Investing Activities (1,864) (4,013) (1,219) (1,569) (1,469) -------------------------------------------------------------------------------------------------------- 279 (2,407) 186 (319) 27 -------------------------------------------------------------------------------------------------------- Cash Flow from Financing Activities (274) 1,426 1,006 329 (100) -------------------------------------------------------------------------------------------------------- 5 (981) 1,192 10 (73) --------------------------------------------------------------------------------------------------------
In 2001 and 2002, we began to invest significantly in two deep-water Gulf of Mexico projects (Aspen and Gunnison), our Syncrude expansion and our Long Lake project. We used our cash flow in 2001 and accessed public debt markets in 2002 to fund these investments. In 2003, Aspen contributed significantly to our cash flow and in late 2003, we pre-funded debt repayments by raising more than $1 billion in senior and subordinated debt. We used these funds in 2004 to repay higher cost debt, and coupled with acquisition credit facilities, acquired the North Sea assets. In 2005, we used our cash flow and the proceeds from asset dispositions to fund our capital program and repay debt. Our marketing business also requires liquidity to support its asset-based trading strategy. Liquidity requirements include cash for working capital, cash or credit lines to fund collateral requirements and risk capital to absorb unexpected market or credit losses. The commercial agreements our marketing business enters into often include financial assurance provisions that allow Nexen and our counterparties to effectively manage credit risk. These agreements typically require posting of collateral when adverse credit-related events occur, such as a reduction in credit ratings. In evaluating our liquidity requirements, we consider the current requirements of our marketing business as well as additional collateral or other payments that could be required in the event of reductions in our credit ratings. FUTURE LIQUIDITY Our future liquidity is primarily dependent on cash flows generated from our operations, existing committed credit facilities and our ability to access debt and equity markets. Assuming WTI of US$55/bbl, we expect our 2006 capital investment program and dividend requirements to exceed our cash flow by more than $350 million. We plan to fund this shortfall by drawing on our unused committed credit facilities. In late 2006, we will also repay $93 million of medium term notes that become due, which we expect to fund using our committed credit facilities. Our cash flow is sensitive to changes in commodity prices and exchange rates. For 2006, we expect cash flow of more than $2.6 billion (before remediation and geological and geophysical expenditures) assuming: ------------------------------------------------------------------------------- WTI (US$/bbl) 55.00 ------------------------------------------------------------------------------- NYMEX Natural Gas (US$/mmbtu) 9.25 ------------------------------------------------------------------------------- US to Canadian Dollar Exchange Rate 0.85 ------------------------------------------------------------------------------- Changes in commodity prices and exchange rates will impact our cash flow and our borrowing requirements. The impact of a variance in any one of the above assumptions on our cash flow is described in the Outlook for 2006 section on page 46. We are in the midst of developing major projects including Buzzard in the North Sea, Long Lake and our coal bed methane project in the Fort Assiniboine area of Alberta. Our anticipated spending on these projects in 2006 and 2007 is as follows: ------------------------------------------------------------------------------- (Cdn$ millions) ------------------------------------------------------------------------------- 2006 1,080 ------------------------------------------------------------------------------- 2007 330 ------------------------------------------------------------------------------- Total Capital Investment 1,410 ------------------------------------------------------------------------------- Given our reliance on cash flows to fund these projects, we implemented a cash flow protection strategy using WTI crude oil put options in late 2004 for 2005 and 2006. For 2006, these put options provide us with an annual average WTI floor price of US$38.17 on 60,000 bbls of oil per day. This strategy reduces the downside risk to our future cash flows in 2006 if commodity prices were to fall when our capital requirements are high, yet still allows us to realize all price upside. Our Buzzard project creates foreign currency exposure as a portion of the capital costs are denominated in British pounds and Euros, while our revenue stream is primarily US dollars. To reduce our exposure to fluctuations in these currencies relative to the US dollar, we purchased foreign currency call options in early 2005 that effectively set a ceiling on most of our British pound and Euro spending exposure from March 2005 to the end of 2006. 50 While these development projects lack exploration risk, they are subject to other risks including higher than anticipated capital costs or delayed start-up. We maintain undrawn committed credit facilities to manage this risk. In addition to our operating cash flows and our undrawn committed credit facilities, we have a US$1.5 billion shelf prospectus available in the US and Canada. At December 31, 2005, the average term to maturity of our long-term debt was 20.5 years. We have the following debt maturities during the next five years:
--------------------------------------------------------------------------------------------- (Cdn$ millions) 2006 2007 2008 2009 2010 --------------------------------------------------------------------------------------------- Term Credit Facilities (1) - - - - - --------------------------------------------------------------------------------------------- Canexus LP Term Credit Facilities - - - 171 - --------------------------------------------------------------------------------------------- Debentures 93 - - - - --------------------------------------------------------------------------------------------- Medium Term Notes - 150 125 - - --------------------------------------------------------------------------------------------- Total 93 150 125 171 - ---------------------------------------------------------------------------------------------
Note: (1) $2.4 billion available until 2010. With our expected cash flow streams, commodity price and foreign exchange hedging strategies, current levels of liquidity, and access to debt and equity markets, we expect to have no difficulties funding our planned capital programs, dividend requirements and debt repayments, or meeting other obligations that may arise from our oil and gas, chemicals and marketing operations. In 2005, we declared common share dividends of $0.20 per share (2004--$0.20, 2003--$0.163). We expect to declare common share dividends of $0.20 per share in 2006. CONTRACTUAL OBLIGATIONS, COMMITMENTS AND GUARANTEES We assume various contractual obligations and commitments in the normal course of our operations and financing activities. We have considered these obligations and commitments in assessing our cash requirements, as noted in the above discussion of future liquidity. They include:
------------------------------------------------------------------------------------------------------------------------ Payments ------------------------------------------------------------------------------------------------------------------------ less than more than (Cdn$ millions) Total 1 year 1-3 years 4-5 years 5 years ------------------------------------------------------------------------------------------------------------------------ Long-Term Debt 3,687 93 275 171 3,148 ------------------------------------------------------------------------------------------------------------------------ Interest on Long-Term Debt 5,086 225 420 402 4,039 ------------------------------------------------------------------------------------------------------------------------ Operating Leases (1) 272 33 63 55 121 ------------------------------------------------------------------------------------------------------------------------ Capital Leases 113 2 10 10 91 ------------------------------------------------------------------------------------------------------------------------ Energy Commodity Contract Liabilities 445 321 102 20 2 ------------------------------------------------------------------------------------------------------------------------ Transportation and Storage Commitments (1) 888 440 230 102 116 ------------------------------------------------------------------------------------------------------------------------ Work Commitments and Purchase Obligations (2) 2,143 1,229 568 261 85 ------------------------------------------------------------------------------------------------------------------------ Asset Retirement Obligations 1,471 21 35 32 1,383 ------------------------------------------------------------------------------------------------------------------------ Other 6 1 2 2 1 ------------------------------------------------------------------------------------------------------------------------ Total 14,111 2,365 1,705 1,055 8,986 ------------------------------------------------------------------------------------------------------------------------
Notes: (1) Payments for operating leases and transportation and storage commitments are deducted from our cash flow from operating activities. (2) Some of these payments relate to work commitments cancellable at our option without penalties or additional fees. Contractual obligations can be financial or non-financial. Financial obligations are known future cash payments that we must make under existing contracts, such as debt and lease arrangements. Non-financial obligations are contractual obligations to perform specified activities such as work commitments. Commercial commitments are contingent obligations that become payable only if certain pre-defined events occur. o Long-term debt amounts are included on our December 31, 2005 Consolidated Balance Sheet. o Operating leases include the minimum lease payment obligations associated with leases for office space, rail cars, vehicles and our processing agreement with Shell that allows our Aspen production to flow through Shell's processing facilities at the Bullwinkle platform. The terms of the processing agreement give Shell an annual option 51 to take payment in cash or in kind. For 2006, Shell has elected to take payment in kind, so the 2006 obligation has been excluded from this table. Instead, it is shown as a royalty and excluded from reserves and production. o Capital leases include pipeline commitments primarily related to future production at Long Lake. o Energy commodity contract liabilities include the purchase and sale of physical quantities of oil and natural gas, and financial derivatives used to manage our exposure to commodity prices. For contracts where the price is based on an index, the amount is based on forward market prices at December 31, 2005. For certain contracts, we may net settle. o Work commitments include non-discretionary capital spending related to drilling, seismic, construction of facilities and other development commitments in our international operations, and includes Long Lake ($422 million), the Buzzard project in the North Sea ($592 million) and at Block 51 in Yemen ($88 million). The timing of certain payments is difficult to determine with certainty. The table has been prepared using our best estimates; the remainder of our 2006 capital investment is discretionary. o We also have included work commitments relating to drilling rigs, which have been contracted to work for us in the North Sea and Gulf of Mexico, totalling $602 million over the next five years. o We have $1,471 million of undiscounted asset retirement obligations. As of December 31, 2005, the discounted value ($611 million) of these estimated obligations has been provided for in our consolidated financial statements (including $21 million of current liabilities). The timing of any payments is difficult to determine with certainty, and the table has been prepared using our best estimates. o We have unfunded obligations under our defined benefit pension and post retirement benefit plans of $86 million (of which $9 million relates to Canexus), and our share of Syncrude's unfunded obligation is $51 million. Our $86 million obligation includes $43 million that is unfunded as a result of statutory limitations. These obligations are backed by irrevocable letters of credit. o We have excluded obligations on our stock option and stock appreciation rights programs as the amount and timing of cash payments are indeterminable. o We have excluded our normal purchase arrangements as they are discretionary and are reflected in our expected cash flow from operating activities and our expected capital expenditures for 2006. o We have excluded our future income tax liabilities as the amount and timing of any cash payments for income taxes are based primarily on taxable income for each fiscal year in the various jurisdictions in which we operate. We have entered into a long-term supply agreement under which we are committed to deliver 35,000 bbls/d of heavy crude oil at market prices beginning mid-2008 for ten years. From time to time, we enter into contracts that require us to indemnify parties against possible claims, particularly when these contracts relate to the sale of assets. On occasion, we provide indemnifications to the purchaser. Generally, a maximum obligation is not stated; therefore, the overall maximum amount cannot be reasonably estimated. We have not made any significant payments related to these indemnifications. Our Risk Management Committee actively monitors our exposure to the above risks and obtains insurance coverage to satisfy potential or future claims as necessary. We believe these matters would not have a material adverse effect on our liquidity, financial condition or results of operations. CREDIT RATINGS Currently, our senior debt is rated BBB- by Standard & Poor's (S&P), Baa2 by Moody's Investor Service, Inc. (Moody's) and BBB by Dominion Bond Rating Service (DBRS). In addition, S&P and DBRS currently rate our outlook as stable while Moody's has a negative outlook. Our strong financial results, ample liquidity and financial flexibility continue to support our credit ratings. FINANCIAL ASSURANCE PROVISIONS IN COMMERCIAL CONTRACTS The commercial agreements our marketing group enters into often include financial assurance provisions that allow Nexen and our counterparties to effectively manage credit risk. The agreements normally require posting of collateral when adverse credit-related events occur such as a reduction in credit ratings. Based on the contracts in place and commodity prices at December 31, 2005, we could be required to post collateral of up to $1.1 billion if we were downgraded to non-investment grade. These obligations are already reflected on our balance sheet. The posting of collateral merely accelerates the payment of such amounts. Just as we may be required to post collateral in the event of a downgrade below investment grade, we have similar provisions in many of our contracts that allow us to demand certain counterparties post collateral with us if they are downgraded to non-investment grade. 52 OFF-BALANCE SHEET ARRANGEMENTS We have no off-balance sheet arrangements that would have a material adverse effect on our liquidity, consolidated financial position or results of operations. We use operating leases in the normal course of business as disclosed in Contractual Obligations, Commitments and Guarantees on page 51 and in Note 15 to the Consolidated Financial Statements in Item 8, which is incorporated herein by reference. CONTINGENCIES We have no contingencies that would have a material adverse effect on our liquidity, consolidated financial position or results of operations. See Note 15 to the Consolidated Financial Statements in Item 8, which is incorporated herein by reference for a discussion of our contingencies. RISK FACTORS Our operations are exposed to various risks, some of which are common to others in our industry and some of which are unique to our operations. COMPETITION The oil and gas industry is highly competitive, particularly in the following areas: o searching for and developing new sources of crude oil and natural gas reserves; o constructing and operating crude oil and natural gas pipelines and facilities; and o transporting and marketing crude oil, natural gas and other petroleum products. Our competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers. The pulp and paper chemicals market is also highly competitive. Key success factors are price, product quality, and logistics and reliability of supply. Competitive forces may result in shortages of prospects to drill, services to carry out exploration, development or operating activities, and infrastructure to produce and transport production. It may also result in an oversupply of crude oil and natural gas. Each of these factors could have a negative impact on costs and prices and, therefore, our financial results. OPERATIONAL RISKS Acquiring, developing and exploring for oil and natural gas involves many risks. These include: o encountering unexpected formations or pressures; o premature declines of reservoirs; o blow-outs, well bore collapse, equipment failures and other accidents; o craterings and sour gas releases; o uncontrollable flows of oil, natural gas or well fluids; and o environmental risks. We operate two facilities that are located in close proximity to populated areas, and each processes materials of potential harm to the local populations. At Balzac, just north of Calgary, we operate a gas plant that has been producing sour gas for over 40 years. In North Vancouver, we operate, indirectly through ownership in Canexus Limited Partnership, a chlor-alkali plant that has been producing chlorine for almost 50 years. We may not be fully insured against all of these risks. Losses resulting from the occurrence of these risks may have a material adverse impact on our financial results. OFFSHORE OPERATIONS Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. Our operations in the Gulf of Mexico have been suspended, from time to time, due to hurricanes or tropical storms. In the last five years, we have had a few instances where production was suspended for an extended period of time and damage to facilities was incurred. In late August 2005, we shut-in all of our production in the Gulf of Mexico, consisting of approximately 50,000 boe/d before royalties, and ceased drilling operations in anticipation of Hurricane Katrina. Production was restored in early September for most of our fields. On September 20, 2005, we again shut-in all of our production and ceased drilling operations in anticipation of Hurricane Rita. While we incurred minimal damage to most of our facilities, extensive damage was incurred to the third party infrastructure necessary to accommodate our production. As a result, our annualized production was reduced approximately 6,000 boe/d. These storms also resulted in damage to rigs under contract 53 with us, which increased our costs and delayed our drilling schedule. In 2002, our facilities at Eugene Island 295 were damaged during Hurricane Lili. Production from this field was suspended for about four months while temporary production facilities were put in place. During this period, production volumes were reduced by approximately 2,500 boe/d. Production was restored at a reduced rate through temporary facilities for approximately six months while installation of new permanent facilities was completed. It is estimated that volumes were reduced by approximately 1,800 boe/d during this period. In each of these instances, there was no significant financial impact after business interruption and property insurance claims. Our exploration and development capital programs in our offshore operations are exposed to risk of delay or additional costs by limited access to drilling rigs. Recent industry pressure in the Gulf of Mexico following storm damage sustained in the 2005 hurricane season has reduced the availability of drilling rigs. Our profitability and success at finding replacement reserves may be reduced by extended delays or higher costs of obtaining drilling rigs. UNCERTAINTY OF RESERVE ESTIMATES Our future crude oil and natural gas reserves and production, and therefore our operating cash flows and results of operations, are highly dependent upon our success in exploiting our current reserve base and acquiring or discovering additional reserves. Without reserve additions through exploration, acquisition or development activities, our reserves and production will decline over time as reserves are produced. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our oil and natural gas reserves will be impaired. Over the past three years, we experienced net negative revisions of 337 million boe to our proved reserves (including Syncrude and before royalties). This includes 258 million boe of economic revisions related to changes in year-end prices and costs, of which 246 million boe relates to the write-off of the reserves at our Long Lake oil sands project as a result of low bitumen prices. The remaining negative revisions of 79 million boe, representing about 10% of worldwide proved reserves, relate to technical revisions primarily on our producing properties. In Canada, the majority of the negative revisions of 56 million boe occurred in 2003 as a result of an ongoing assessment of the future production profiles of our properties and a reduction of proved undeveloped reserves based on drilling results and updated geologic mapping. In Yemen, the negative revisions of 30 million boe occurred largely in 2003 and 2004 and resulted primarily from lower-than-expected production performance, drilling results and updated geological mapping. In the United States, negative revisions of 21 million boe occurred largely in 2004 and 2005 and resulted primarily from lower-than-expected production performance at our deep water Aspen property and at various properties on the Shelf. These negative revisions were somewhat offset by a positive revision of 17 million boe in our Buzzard field due to updated geologic mapping. About two-thirds of the 79 million boe of net negative revisions were recognized as proved reserves based on projected future production performance of producing properties. These projections considered historical performance and expected future changes in production using all available engineering and geologic data. However, subsequent production performance did not meet our projections due to such factors as sand production, steeper than expected declines due to higher water cuts and the unexpected loss of well productivity. The remainder of the reserves were recognized as proved undeveloped reserves based on production performance, well control and geologic mapping using seismic and other data. Lower than expected production, greater sweep efficiencies, and unsuccessful drilling caused us to revise our proved reserves estimates downward. Under SEC rules, we must recognize our oil sands as bitumen reserves rather than the upgraded premium synthetic crude oil that we expect to produce from Long Lake. As a result, we expect price-related revisions, both positive and negative, to occur in the future as the economic producibility of our bitumen and heavy oil reserves are sensitive to year-end prices. In particular, since we recognize our oil sands as bitumen reserves and they are related to one project, all or none of the reserves will likely be considered economic depending on the year-end prices for bitumen, diluent and natural gas, even though the Long Lake project has virtually no exposure to these factors. INCREASE IN PROVED UNDEVELOPED RESERVES The definition of proved reserves includes proved undeveloped reserves that are expected to be recovered from new wells on certain undrilled acreage or from existing wells where a relatively major expenditure is still required before such wells may begin production. Such reserves may be recognized when plans are in place to make the required investments to convert these undeveloped reserves to producing. Circumstances such as a sustained decline in commodity prices or poorer than expected results from initial activities could cause a change in the plans which could result in a material change in our reserves estimates. During the past 3 years, our total proved undeveloped reserves before royalties have increased from 125 mmboe to 180 mmboe (87 mmboe to 165 mmboe after royalties). As a result, our proved undeveloped reserves have increased from 24% to 38% of our proved reserves excluding Syncrude (22% to 42% after royalties). Proved undeveloped reserves increased in the United Kingdom as a result of our acquisition and ongoing development of the Buzzard Field. In all other areas, they have declined primarily due to the completion of the development of Block 51 in Yemen and the drilling of a portion of the undrilled acreage elsewhere. 54 HEAVY OIL OPERATIONS Heavy oil is characterized by high specific gravity or weight and high viscosity or resistance to flow. Because of these features, heavy oil is more difficult and expensive to extract, transport and refine than other types of oil. Heavy oil also yields a lower price relative to light oil and gas, as a smaller percentage of high-value petroleum products can be refined from heavy oil. As a result, our heavy oil operations are exposed to the following risks: o additional costs may be incurred to purchase diluent to transport heavy oil; o there could be a shortfall in the supply of diluent which may cause its price to increase; and o the market for heavy oil is more limited than for light oil making it more susceptible to supply and demand fundamentals which may cause the price to decline. Any one or combination of these factors could cause some of our heavy oil properties to become uneconomic to produce and/or result in negative reserve revisions. Additional risk factors relating to our Long Lake oil sands project are provided under "Risk Factors Relating to Long Lake". RISK FACTORS RELATING TO LONG LAKE Our Long Lake project is planned as a fully integrated production, upgrading and co-generation facility. We intend to use Steam Assisted Gravity Drainage (SAGD) technology to recover bitumen from oil sands. As designed, the bitumen will be partially upgraded using conventional distillation, de-asphalting and thermal cracking (the proprietary OrCrude(TM) process), followed by conventional hydrocracking to produce a sweet, premium synthetic crude oil. All the individual components of the technology used in the process are currently used in commercial applications around the world. The OrCrude(TM) process also yields liquid asphaltines that will be gasified into a syngas. This syngas will be used as a fuel source for the SAGD process, a source of hydrogen for use in the upgrading process, and to generate electricity through a co-generation facility. We have a 50% working interest in this project, and our share of the capital costs is estimated to be $2.3 billion ($4.6 billion gross). Given the initial investment and operating costs to produce and upgrade bitumen, the payout period for the project is longer and the economic return is lower than a conventional light oil project with an equal volume of reserves. Risks associated with our Long Lake oil sands project include the following: STATUS OF THE LONG LAKE PROJECT The Long Lake project is currently in the construction stage. There is a risk that actual costs to construct and develop may be higher than expected or that the project may not be completed on time or at all due to many factors, including: o construction performance falling below expected levels of output or efficiency; o labour disputes, disruptions or declines in productivity; o increases in materials or labour costs; o inability to attract sufficient numbers of qualified workers; o design errors; o contractor or operator errors; o non-performance by third-party contractors; o changes in project scope; o delays in obtaining, or conditions imposed by, regulatory approvals; o breakdown or failure of equipment or processes; o violation of permit requirements; o catastrophic events such as fires, earthquakes, storms or explosions; and o disruption in the supply of energy. Actual costs to construct and develop the project will vary from our estimates, and such variances may be significant. In the formative stage of the project, our capital cost estimate was approximately $2.3 billion (gross). After completing further project definition, engineering and reviewing pilot results, we changed the scope of the project to include co-generation facilities, planned for certain redundancies within the upgrader, and applied more conservative estimates to labour productivity. As a result, the capital cost estimate at the time of our Board's sanctioning the project in February 2004 was $3.4 billion (gross). In December 2004, we accelerated the drilling of an additional well pad consisting of 13 well-pairs to ensure certainty and reliability of bitumen production at the commencement of upgrader operations at a cost of $98 million (gross). In early 2006 we further modified the project design by adding steam generation capacity and soot handling equipment at a cost of $360 million (gross). High activity in the oil sands region is placing ongoing pressure on the costs of labour and services. In addition, labour productivity has been lower than anticipated, requiring a larger workforce to maintain progress. After a review of all trends, the projected cost of Long Lake has been increased to $4.6 billion (gross). 55 SAGD BITUMEN RECOVERY PROCESS SAGD has been used in Western Canada to increase recoveries from conventional heavy oil reservoirs for over a decade. However, application of SAGD to the insitu recovery of bitumen from oil sands is relatively new. Some of the SAGD oil sands applications to date have been pilot projects, however there are several commercial SAGD projects in steady state operation. Our estimates for performance and recoverable volumes for the Long Lake project are based primarily on our three well-pair SAGD pilot and industry performance from SAGD operations in like reservoirs in the McMurray formation in the Athabasca oil sands. Using this data, our assumptions included average well-pair productivity of 900 bbls/d of bitumen and a steam-to-oil ratio of 2.5. There can be no assurance that our SAGD operation will produce bitumen at the expected levels or steam-to-oil ratio. If the assumed production rates or steam-to-oil ratio are not achieved, we might have to drill additional wells to maintain optimal production levels, construct additional steam generating capacity and/or purchase natural gas for additional steam generation. These could have a significant adverse impact on the future activities and economic return of the Long Lake project. BITUMEN UPGRADING PROCESS The proprietary OrCrude(TM) process we are using to upgrade raw bitumen to synthetic crude will be the first commercial application of the process although we have operated it in a 500 bbls/d demonstration plant. There can be no assurance that the commercial upgrader being constructed at Long Lake will achieve the same or similar results as the demonstration plant or the results which are forecast. If we are unable to upgrade the bitumen for any reason we may decide to sell it as bitumen without upgrading it, which would expose us to the following risks: o the market for bitumen is limited; o additional costs would be incurred to purchase diluent for blending and transporting bitumen; o there could be a shortfall in the supply of diluent which may cause its price to increase; o the market price for bitumen is relatively low reflecting its quality differential; and o additional costs would be incurred to purchase natural gas for use in generating steam for the SAGD process since we would not be producing syngas from the upgrading process. These factors could have a significant adverse impact on the future activities and economic returns of the Long Lake project. If any of these factors arise, our operating costs would increase and our revenues would decrease from those we have assumed. This would cause a material decrease in expected earnings from the project and the project may not be profitable under these conditions. DEPENDANCE ON OPTI CANADA We are undertaking the Long Lake project jointly with OPTI Canada (OPTI) pursuant to a joint venture agreement governing the construction, ownership and joint operation of the project. The agreement provides for the creation of a management committee that is responsible for the supervision and direction of the management and operation of the project, the supervision and control of the operators and all other matters relating to the development of the project. If our interest in any element of the project falls below 25%, OPTI may be able to make decisions respecting that element without our input, which may adversely affect our operations. DEPENDANCE ON PROPRIETARY TECHNOLOGY The success of the project and our investment depends to a significant extent on the proprietary technology of OPTI and proprietary technology of third parties that has been, or is required to be, licensed by OPTI. OPTI currently relies on intellectual property rights and other contractual or proprietary rights, including (without limitation) copyright, trademark laws, trade secrets, confidentiality procedures, contractual provisions, licenses and patents, to secure the rights to utilize its proprietary technology and the proprietary technology of third parties. OPTI may have to engage in litigation in order to protect the validity of its patents or other intellectual property rights, or to determine the validity or scope of the patents or proprietary rights of third parties. This kind of litigation can be time-consuming and expensive, regardless of whether or not OPTI is successful. The process of seeking patent protection can itself be long and expensive, and there can be no assurance that any currently pending or future patent applications of OPTI or such third parties will actually result in issued patents, or that, even if patents are issued, they will be of sufficient scope or strength to provide meaningful protection or any commercial advantage to OPTI. Furthermore, others may develop technologies that are similar or superior to the technology of OPTI or such third parties or design around the patents owned by OPTI and/or such third parties. There is also a risk that OPTI may not be able to enter into licensing arrangements with third parties for the additional technologies required for the possible further expansion of the Long Lake upgrader. 56 OPERATIONAL HAZARDS The operation of the project will be subject to the customary hazards of recovering, transporting and processing hydrocarbons, such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts and oil spills. A casualty occurrence might result in the loss of equipment or life, as well as injury or property damage. We may not carry insurance with respect to all potential casualty occurrences and disruptions. It cannot be assured that our insurance will be sufficient to cover any such casualty occurrences or disruptions. The project could be interrupted by natural disasters or other events beyond our control. Losses and liabilities arising from uninsured or under-insured events could have a material adverse effect on the project and on our business, financial condition and results of operations. Recovering bitumen from oil sands and upgrading the recovered bitumen into synthetic crude oil and other products involve particular risks and uncertainties. The project is susceptible to loss of production, slowdowns or restrictions on its ability to produce higher value products due to the interdependence of its component systems. Severe climatic conditions can cause reduced production and in some situations result in higher costs. SAGD bitumen recovery facilities and development and expansion of production can entail significant capital outlays. The costs associated with synthetic crude oil production are largely fixed and, as a result, operating costs per unit are largely dependent on levels of production. The Long Lake SAGD operation and upgrader will process large volumes of hydrocarbons at high pressure and temperatures and will handle large volumes of high-pressure steam. Equipment failures could result in damage to the project's facilities and liability to third parties against which we may not be able to fully insure or may elect not to insure because of high premium costs or for other reasons. Certain components of the Long Lake project will produce sour gas, which is gas containing hydrogen sulphide. Sour gas is a colourless, corrosive gas that is toxic at relatively low levels to plants and animals, including humans. The project will include integrated facilities for handling and treating the sour gas, including the use of gas sweetening units, sulphur recovery systems and emergency flaring systems. Failures or leaks from these systems or other exposure to sour gas produced as part of the project could result in damage to other equipment, liability to third parties, adverse effect to humans, animals and the environment, or the shut down of operations. The Long Lake project will produce carbon dioxide emissions. Carbon dioxide is a greenhouse gas that will be regulated by the Kyoto Protocol. Canada's commitments under the Kyoto Protocol are expected to come into effect in 2008. Risk factors relating to climate change initiatives are provided under "Climate Change". ABORIGINAL CLAIMS Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of Western Canada. Certain aboriginal peoples have filed a claim against the Government of Canada, the Province of Alberta, certain governmental entities and the regional municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta) claiming, among other things, aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which the project and most of the other oil sands operations in Alberta are located. Such claims, if successful, could have a significant adverse effect on the project and on us. COMPETITION The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of oil interests and the distribution and marketing of petroleum products. The Long Lake project competes with other producers of synthetic crude oil blends and other producers of conventional crude oil. Some of the conventional producers have lower operating costs than the project is anticipated to have. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. A number of companies other than OPTI and us have announced plans to enter the oil sands business and begin production of synthetic crude oil, or expand existing operations. Expansion of existing operations and development of new projects could materially increase the supply of synthetic crude oil and other competing crude oil products in the marketplace. Depending on the levels of future demand, increased supplies could have a negative impact on prices. CONCENTRATION OF PRODUCING ASSETS A portion of our production is generated from highly productive individual wells or central production facilities. Examples include: o central processing facilities, oil pipelines, and export terminal at our two Yemen operations; o Gunnison SPAR production platform in the Gulf of Mexico; o highly productive Aspen wells tied-in to a third-party processing facility in the Gulf of Mexico; and o Scott production platform in the North Sea. 57 As significant production is generated from each of these assets, any single event causing an interruption to these operations could result in the loss of production. Our insurance for physical damage and business interruption does not provide for losses arising from equipment failures. COAL BED METHANE Coal bed methane (CBM) is commonly referred to as an unconventional form of natural gas because it is primarily stored through adsorption by the coal itself rather than in the pore space of the rock like most conventional gas. The gas is released in response to a drop in pressure in the coal. If the coal is water saturated, water generally needs to be extracted to reduce the pressure and allow gas production to occur. CBM wells typically have lower producing rates and reserves per well than conventional gas wells, although this varies by area. Regulatory approval is required to drill more than one well per section. As a result, the timing of drilling programs and land development can be uncertain. The Mannville coals in the Fort Assiniboine region of Alberta are deeper than other producing CBM projects and are water saturated. A significant period of time may be required to sufficiently dewater the coals to determine if commercial production is feasible. As a result, we may have to invest significant capital in CBM assets before they achieve commercial rates of production. The wells may never achieve commercial rates of production as there are no commercially proven Mannville CBM projects in operation. CBM projects in some areas of the United States have had negative public reaction due to certain water disposal practices. In Canada, as in the United States, water disposal practices are regulated to ensure public safety and water conservation. Nevertheless, negative public perception around CBM production could impede our access to the resource. COMMITMENTS TO PROJECTS UNDER DEVELOPMENT We have significant commitments in connection with various development activities currently underway. Final hookups and commissioning with respect to the Buzzard platform in the North Sea are nearing completion, and we expect production start-up prior to the end of the year. We are exposed to the possibility of delays in the commencement of commercial production, which may be due to many factors, including: o commissioning delays; o contractor or operator errors; o breakdown or failure of equipment or processes; o quality of oil and gas produced; o violation of permit requirements; and o catastrophic events such as fires, storms or explosions. At Long Lake, all SAGD wells have been drilled and completed, SAGD module fabrication is complete, all modules are on site and construction is approximately 90% complete. With respect to the Long Lake upgrader, module fabrication is largely complete and over 90% of the modules are on site. Construction of the upgrader is approximately 60% complete and start-up remains scheduled for the second half of 2007. At Long Lake, we are exposed to the possibility of cost overruns and/or delays in the commencement of commercial production, which may be significant. Specific risk factors relating to our Long Lake oil sands project are provided under the heading "Risk Factors Relating to Long Lake". POLITICAL RISK We operate in numerous countries, some of which may be considered politically and economically unstable. Our operations and related assets are subject to the risks of actions by governmental authorities, insurgent groups or terrorists. For instance, on September 15, 2006 our oil export terminal in Yemen was assaulted by two explosive laden vehicles. One worker was killed and two others received minor injuries. None of the attackers survived. The ability of the terminal to receive and export oil was not affected and operations are continuing as normal. There can be no assurance that we will be successful in protecting ourselves against these risks and the related financial consequences. In particular, our operations in Yemen expose us to potential material adverse financial consequences. In 2005, Yemen accounted for $536 million or 46% of our net income and this is expected to decline somewhat in 2006 as production declines on Masila are partially offset by production from completion of development activities on Block 51. ENVIRONMENTAL RISK Environmental risks inherent in the oil and gas and chemicals industries are becoming increasingly sensitive as related laws and regulations become more stringent worldwide. Many of these laws and regulations require us to remove or remedy the effect of our activities on the environment at present and former operating sites, including dismantling production facilities and remediating damage caused by the disposal or release of specified substances. 58 CLIMATE CHANGE The Kyoto Protocol came into force on February 16, 2005. Canada ratified the Kyoto Protocol in December 2002. In 1997, Canada committed to an emission reduction of 6% below 1990 levels during the First Commitment period (2008 to 2012). Since that time the Canadian federal government and various provincial governments have grappled with the issue of climate change and a number of proposals have come and gone. Most recently, Bill C-30 (Canada's Clean Air Act) was introduced to Parliament for first reading. This Bill contains proposals to deal with criteria air contaminants (CACs) and greenhouse gases (GHGs) and outlines proposed changes to the Canadian Environmental Protection Act 1999, the Energy Efficiency Act and the Motor Vehicle Fuel Conservation Standards Act. The proposals seek to apply intensity-based targets for GHGs and absolute caps on CACs in the period up to 2020-2025 ultimately leading to absolute caps on GHGs. It is unclear if and when Bill C-30 will become law. Any required reductions in the GHGs emitted from our operations could result in increases in our capital or operating expenses, or reduced operating rates, especially those related to the Long Lake project, which could have an adverse effect on our results of operations and financial condition. CRITICAL ACCOUNTING ESTIMATES We make estimates and assumptions that affect the reported amounts of our assets and liabilities and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and our revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes and the determination of proved reserves on an ongoing basis. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. Our critical accounting estimates are discussed below. OIL AND GAS ACCOUNTING - RESERVES DETERMINATION We follow the successful efforts method of accounting for our oil and gas activities, as described in Note 1 to our Consolidated Financial Statements. Successful efforts accounting depends on the estimated reserves we believe are recoverable from our oil and gas properties. The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including: o expected reservoir characteristics based on geological, geophysical and engineering assessments; o future production rates based on historical performance and expected future operating and investment activities; o future oil and gas prices and quality differentials; o assumed effects of regulation by governmental agencies; and o future development and operating costs. We believe these factors and assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook modified to reflect SEC requirements. Reserve estimates for each property are internally prepared at least annually by the property's reservoir engineer. They are reviewed by engineers familiar with the property and by divisional management. An Executive Reserves Committee, including our CEO, CFO and Board-appointed internal qualified reserves evaluator, meet with divisional reserves personnel to review the estimates and any changes from previous estimates. The internal qualified reserves evaluator assesses whether our reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, have been prepared in accordance with our reserve standards. His opinion stating that the reserves information has, in all material respects, been prepared according to our reserves standards is included in an exhibit to this Form 10-K. 59 Our reserves are based on internal estimates. To increase our confidence in our estimates, we have at least 80% of our oil and gas and Syncrude reserves either evaluated or audited annually by independent qualified reserves consultants. Given that reserves estimates are based on numerous assumptions, interpretations and judgements, differences frequently arise between the estimates prepared by different qualified estimators. When the initial estimate on the portfolio of properties differs by greater than 10%, we work with the independent reserves consultant to reconcile the difference to within 10%. Estimates pertaining to individual properties within the portfolio often differ by significantly more than 10%, either positively or negatively. We do not attempt to resolve each property to within 10% as it would be time and cost prohibitive given the number of wells in which we have an interest. The nature and extent of the independent evaluations and audits, and the results thereof, are provided in the section on Reserves, Production and Related Information on page 17. The Board of Directors has established a Reserves Review Committee (Reserves Committee) to assist the Board and the Audit and Conduct Review Committee to oversee the annual review of our oil and gas reserves and related disclosures. The Reserves Committee is comprised of three or more directors, the majority of whom are independent, and each being familiar with estimating oil and gas reserves. The Reserves Committee meets with management periodically to review the reserves process, the portfolio of properties selected by management for independent assessment, results and related disclosures. The Reserves Committee appoints and meets with each of the internal qualified reserves evaluator and independent reserves consultants independent of management to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reserves consultants, their independence. The Reserves Committee has reviewed Nexen's procedures for preparing the reserves estimates and related disclosures. It has reviewed the information with management, and met with the internal qualified reserves evaluator and the independent qualified reserves consultants. As a result of this, the Reserves Committee is satisfied that the internally-estimated reserves are reliable and free of material misstatement. Based on the recommendation of the Reserves Committee, the Board has approved the reserves estimates and related disclosures in the Form 10-K. Reserves estimates are critical to many of our accounting estimates, including: o Determining whether or not an exploratory well has found economically producible reserves. If successful, we capitalize the costs of the well, and if not, we expense the costs immediately. In 2005, $143 million of our total $456 million spent on exploration drilling was expensed. If none of our drilling had been successful, our net income would have decreased by $206 million after tax. o Calculating our unit-of-production depletion rates. Both proved and proved developed reserves (1) estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense. Proved reserves are used where a property is acquired and proved developed reserves are used where a property is drilled and developed. In 2005, oil and gas and Syncrude depletion of $628 million was recorded in depletion, depreciation, amortization and impairment expense. If our reserves estimates changed by 10%, our depletion, depreciation, amortization and impairment expense would have changed by approximately $42 million, after tax, assuming no other changes to our reserves profiles. o Assessing, when necessary, our oil and gas assets for impairment. Estimated future undiscounted cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below. Since we do not have any loan covenants directly linked to reserves, it would take a significant decrease in our proved reserves to limit our ability to borrow money under our term credit facilities, as previously described in the Liquidity section of the MD&A. OIL AND GAS ACCOUNTING -- IMPAIRMENT We evaluate our oil and gas properties for impairment if an adverse event or change occurs. Among other things, this might include falling oil and gas prices, a significant revision to our reserves estimates, changes in operating costs, or significant or adverse political changes. If one of these occurs, we assess estimated undiscounted future cash flows for affected properties to determine if they are impaired. If the undiscounted future cash flows for a property are less than the carrying amount of that property, we calculate its fair value using a discounted cash flow approach. The property is then written down to its fair value. We assessed our oil and gas properties for impairment at the end of 2005 and found no impairments were required based on our assumptions. Cash flow estimates for our impairment assessments require assumptions about two primary elements--future prices and reserves. 60 Our estimates of future prices require significant judgements about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility--over the last five years, prices for WTI and NYMEX gas have ranged from US$17/bbl to US$71/bbl and US$2/mmbtu to US$19/mmbtu, respectively. Our forecasts for oil and gas revenues are based on prices derived from a consensus of future price forecasts amongst industry analysts and our own assessments. Our estimates of future cash flows generally assume our long-term price forecast and forecast operating and development costs. Given the significant assumptions required and the possibility that actual conditions will differ, we consider the assessment of impairment to be a critical accounting estimate. A change in this estimate would impact all except our chemicals business. If forecast WTI crude oil prices were to fall to mid-US$20/bbl levels our initial assessment of impairment indicators would not change. Although oil and gas prices fluctuate a great deal in the short-term, they are typically stable over a longer-time horizon. This mitigates the potential for impairment. Any impairment charges would lower our net income. It is difficult to determine and assess the impact of a decrease in our proved reserves on our impairment tests. The relationship between the reserves estimate and the estimated undiscounted cash flows, and the nature of the property-by-property impairment test, is complex. As a result, we are unable to provide a reasonable sensitivity analysis of the impact that a reserves estimate decrease would have on our assessment of impairment. (1) "Proved" oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids that geological and engineering data demonstrate with reasonable certainty can be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered "proved" if economic producibility is supported by either actual production or a conclusive formation test. "Proved developed" oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. ASSET RETIREMENT OBLIGATIONS We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future asset retirement obligations requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. We record asset retirement obligations in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities and chemical plants. In arriving at amounts recorded, numerous assumptions and judgments are made with respect to ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and expected changes in legal, regulatory, environmental and political environments. The asset retirement obligations we have recorded result in an increase to the carrying cost of our property, plant and equipment. The obligations are accreted with the passage of time. A change in any one of our assumptions could impact our asset retirement obligations, our property, plant and equipment and our net income. It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results. We are confident, however, that our assumptions are reasonable. BUSINESS COMBINATION - PURCHASE PRICE ALLOCATION During the fourth quarter of 2004, we acquired a company operating and exploring oil and gas properties located in the North Sea. We accounted for this acquisition using the purchase method of accounting. Under this method, we were required to record on our consolidated balance sheet the estimated fair values of the acquired company's assets and liabilities at the acquisition date. The excess of the purchase price over the fair values of the tangible and intangible net assets acquired was recorded as goodwill. We have made various assumptions in determining the fair values of the acquired company's assets and liabilities. The most significant assumptions and judgments made relate to the estimation of the fair value of the oil and gas properties. To determine the fair value of these properties, we estimated (a) oil and gas reserves in accordance with our reserve standards, and (b) future prices of oil and gas. Our reserve estimates were based on the work performed by our engineers and outside consultants. The judgments associated with these estimated reserves are described earlier in our critical accounting estimates discussion entitled "Oil and Gas Accounting--Reserves Determination". Our estimates of future prices were based on prices derived from a consensus of future price forecasts amongst industry analysts and our own assessments. The judgments associated with these estimates are described earlier in our critical accounting estimates discussion entitled "Oil and Gas Accounting--Impairment". We applied our estimated future prices to the estimated reserves quantities acquired, and we estimated future operating and development costs, to arrive at estimated future net revenues for the properties acquired. For proved properties, we discounted the future net revenues using after-tax discount rates. The same principles were applied in arriving at the fair value of unproved properties acquired. These unproved properties generally represent the value of the probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved 61 reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, an appropriate risk-weighting factor was applied to the discounted future net revenues of the probable and possible reserves in each particular instance. If the fair value allocated to oil and gas properties acquired had been decreased by $50 million, future income tax liabilities would have decreased by $20 million and goodwill would have increased by $30 million. FUTURE INCOME TAXES We follow the liability method of accounting for income taxes whereby future income tax assets and liabilities are recognized based on temporary differences in reported amounts for financial statement and tax purposes. We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes. NEW ACCOUNTING PRONOUNCEMENTS CANADIAN PRONOUNCEMENTS In an effort to harmonize Canadian GAAP with US GAAP, the Canadian Accounting Standards Board (AcSB) has issued sections: o 1530, Comprehensive Income; o 3855, Financial Instruments--Recognition and Measurement; and o 3865, Hedges. Under these new standards, all financial assets should be measured at fair value with the exception of loans, receivables and investments that are intended to be held to maturity and certain equity investments, which should be measured at cost. Similarly, all financial liabilities should be measured at fair value when they are held for trading or they are derivatives. Gains and losses on financial instruments measured at fair value will be recognized in the income statement in the periods they arise with the exception of gains and losses arising from: o financial assets held for sale, for which unrealized gains and losses are deferred in other comprehensive income until sold or impaired; and o certain financial instruments that qualify for hedge accounting. Sections 3855 and 3865 make use of "other comprehensive income". Other comprehensive income comprises revenues, expenses, gains and losses that are recognized in comprehensive income, but are excluded from net income. Unrealized gains and losses on qualifying hedging instruments, translation of self-sustaining foreign operations, and unrealized gains or losses on financial instruments held for sale will be included in other comprehensive income and reclassified to net income when realized. Comprehensive income and its components will be a required disclosure under the new standard. These new standards are effective for fiscal years beginning on or after October 1, 2006 and early adoption is permitted. Adoption of these standards as at December 31, 2005 would have the following impact on our Consolidated Financial Statements: ------------------------------------------------------------------------------- Increase/ (Cdn$ millions) (Decrease) ------------------------------------------------------------------------------- Accounts Payable 35 ------------------------------------------------------------------------------- Future Income Tax Liabilities (11) ------------------------------------------------------------------------------- Shareholder's Equity (24) ------------------------------------------------------------------------------- In June 2005, the AcSB issued Section 3831, Non-Monetary Transactions, which replaces Section 3830 and requires all non-monetary transactions to be measured at fair value unless: o the transaction lacks commercial substance; o the transaction is an exchange of a product or property held for sale in the ordinary course of business for a product or property to be sold in the same line of business to facilitate sales to customers other than the parties to the exchange; 62 o neither the fair value of the assets or services received nor the fair value of the assets or services given up is reliably measurable; or o the transaction is a non-monetary, non-reciprocal transfer to owners that represents a spin-off or other form of restructuring or liquidation. The new requirements apply to non-monetary transactions initiated in periods beginning on or after January 1, 2006. Earlier adoption is permitted as of the beginning of a period beginning on or after July 1, 2005. We do not expect the adoption of this section will have any material impact on our results of operations or financial position. In December 2005, the CICA's Emerging Issues Committee issued Abstract 159, Conditional Asset Retirement Obligations (EIC-159). EIC-159 clarifies that the term conditional asset retirement obligation, as used in CICA Handbook Section 3110, Asset Retirement Obligations refers to a legal obligation to perform an asset retirement activity where the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. EIC-159 also clarifies when there would be sufficient information to reasonably estimate the fair value of an asset retirement obligation. EIC-159 is effective for interim and annual reporting periods ending after March 31, 2006. We do not expect the adoption of this section will have any material impact on our results of operations or financial position. US PRONOUNCEMENTS In November 2004, the Financial Accounting Standards Board (FASB) issued Statement 151, Inventory Costs. This statement amends ARB 43 to clarify that: o abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) should be recognized as current-period charges; and o requires the allocation of fixed production overhead to inventory based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position. In December 2004, the FASB issued Statement 123(R), Share-Based Payments. This statement revises Statement 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. Statement 123(R) requires all stock-based awards issued to employees to be measured at fair-value and to be expensed in the income statement. This statement is effective for fiscal years beginning after June 15, 2005. We are currently expensing stock-based awards issued to employees using the fair-value method for equity-based awards and the intrinsic method for liability-based awards. Adoption of this standard will change our expense under US GAAP for tandem options and stock appreciation rights as these awards will be measured using the fair-value method rather than the intrinsic method. Upon implementing the new rules, we expect to record an expense for US GAAP purposes of $3 million ($2 million net of income taxes) in 2006, reflecting the cumulative effect of the change in accounting policy. In December 2004, the FASB issued Statement 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance test and fair value is determinable, the transaction must be accounted for at fair value resulting in the recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position. In March 2005, the FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on our results of operations or financial position. 63 In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry. In the mining industry, companies may be required to remove overburden and other mine waste materials to access mineral deposits. The EITF concluded that the costs of removing overburden and waste materials, often referred to as "stripping costs", incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections, which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. In the absence of explicit transition provisions provided for in new or existing accounting pronouncements, Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to do so. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In September 2005, the EITF reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This issue addresses the question of when it is appropriate to measure purchase and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. The consensus should be applied to new arrangements entered into and modifications or renewals of existing agreements, beginning with the second quarter of 2006. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to normal market risks inherent in the oil and gas and chemicals business, including commodity price risk, foreign-currency rate risk, interest rate risk and credit risk. We recognize these risks and manage our operations to minimize our exposures to the extent practical. NON-TRADING COMMODITY PRICE RISK Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are commodities which are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in world crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, such prices also may affect the value of our oil and gas properties and our level of spending for oil and gas exploration and development. Our crude oil prices are based on various reference prices, primarily the WTI crude oil reference price and other prices which generally track the movement in WTI. Adjustments are made to the reference prices to reflect quality differentials and transportation. WTI and other international reference prices are affected by numerous and complex worldwide factors such as supply and demand fundamentals, economic outlooks, production quotas set by the Organization of Petroleum Exporting Countries and political events. Quality differentials are affected by local supply and demand factors. To a lesser extent we are also exposed to natural gas price movements. Natural gas prices are generally influenced by oil prices and North American supply and demand, and to a lesser extent local market conditions. In 2005, WTI averaged US$56.58/bbl reaching a high of US$70.85/bbl and a low of US$41.25/bbl. NYMEX natural gas prices averaged US$8.99/mmbtu in 2005, reaching a high of US$15.78/mmbtu and a low of US$5.71/mmbtu. 64 Our sensitivities to commodity prices and the expected impact on our 2006 cash flow from operating activities and net income are as follows: ------------------------------------------------------------------------------- (Cdn$ millions) Cash Flow Net INcome ------------------------------------------------------------------------------- WTI--US$1 Change 40 32 ------------------------------------------------------------------------------- NYMEX Natural Gas--US$0.10 Change 7 6 ------------------------------------------------------------------------------- These sensitivities to changes in benchmark prices for crude oil and natural gas are based on our estimated 2006 production levels for crude oil and natural gas and assume a Canadian/US dollar exchange rate of 85(cents). Our estimated crude oil and natural gas production range for 2006 is between 220,000 and 240,000 boe/d before royalties, of which natural gas represents approximately 20%. The majority of our oil and gas production is sold under short-term contracts, exposing us to short-term price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. From time to time, we actively manage these risks by using commodity futures, forwards, swaps and options. In 2004, we purchased WTI put options to manage the commodity price risk exposure on a portion of our oil production in 2005 and 2006. In 2006, these options establish an annual average WTI floor price of US$38/bbl on 60,000 bbls/d of production. FOREIGN CURRENCY RISK A substantial portion of our activities are transacted in or referenced to US dollars including: o sales of crude oil, natural gas and certain chemicals products; o capital spending and expenses for our oil and gas and chemicals operations; and o short-term and long-term borrowings. The Canadian/US dollar exchange rate averaged 0.8253(cents) in 2005 with a high of 0.8690(cents) and a low of 0.7872(cents). Our sensitivities to the US dollar and the expected impact of a one cent change on our 2006 cash flow from operating activities, net income, capital expenditures and long-term debt are as follows:
---------------------------------------------------------------------------------------------------- Capital ---------------------------------------------------------------------------------------------------- Cash Net Long-Term (Cdn$ millions) Flow Income Expenditures Debt ---------------------------------------------------------------------------------------------------- $0.01 Change in US to Canadian Dollar 25 12 18 38 ----------------------------------------------------------------------------------------------------
Our sensitivities to changes in the Canadian/US dollar exchange rate are calculated based on projected revenues, expenses, capital expenditures and US-dollar denominated long-term debt for 2006. These estimates are based on a WTI price for crude oil of US$55.00/bbl, a NYMEX natural gas price of US$9.25/mcf and a Canadian/US dollar exchange rate of 85(cents). We manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Net revenue from our foreign operations and our US-dollar borrowings are generally used to fund US-dollar capital expenditures and debt repayments. Since the timing of cash inflows and outflows is not necessarily interrelated, particularly for capital expenditures, we maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows. We designate our US-dollar borrowings as a hedge against our US-dollar net investment in foreign operations. Our Buzzard project in the North Sea creates foreign currency exposure as a portion of the capital costs are denominated in British pounds (GBP) and Euros. In order to reduce our exposure to fluctuations in these currencies relative to the US dollar, we purchased foreign currency call options in early 2005. These options set a ceiling on most of our British pound and Euro spending exposure from February 2005 through to the end of 2006. These call options effectively set a maximum GBP-US$ exchange rate of 1.95 on a total of GBP 84 million for the period March 2005 through June 2005, and a maximum rate of 2.00 on a total of GBP 185 million for the period July 2005 through December 2006. With respect to our Euro exposure, the call options effectively set a maximum Euro-US$ exchange rate of 65 1.40 on a total of Euros 59 million for the period February through September 2005. Managing our exchange rate exposure through the use of call options caps our exposure if the US dollar weakens relative to the British pound and the Euro but allows us to benefit fully from any strengthening of the US dollar relative to these currencies. Our chemicals operations are exposed to changes in the US-dollar exchange rate as a portion of their sales are denominated in US-dollars. In connection with the Canexus initial public offering, we purchased US-dollar call options to reduce this exposure. These call options give Canexus the right to sell US$11 million monthly and purchase Canadian dollars at an exchange rate of US$0.813 until August 2006. We do not have any material exposure to highly inflationary foreign currencies. We occasionally use derivative instruments to effectively convert cash flows from Canadian to US dollars and vice versa. At December 31, 2005, we held a foreign currency derivative instrument that obligates us and the counterparty to exchange principal and interest amounts. In November 2006, we will pay US$37 million and receive Cdn $50 million. INTEREST RISK We are exposed to fluctuations in short-term interest rates from our floating-rate debt and, to a lesser extent, our derivative instruments and long-term debt, as their market value is sensitive to interest rate fluctuations. To minimize our exposure to interest rate fluctuations, we occasionally use derivative instruments. Short-term interest rates for US-dollar borrowings averaged 4.1% in 2005, reaching a high of 4.8% and low of 3.5%. Our sensitivity to interest rates and the expected impact of a 1% change in interest rates on our 2006 cash flow from operating activities and net income is as follows: ------------------------------------------------------------------------------- (Cdn$ millions) Cash Flow Net Income ------------------------------------------------------------------------------- Interest Rates--1% change in rates 4 3 ------------------------------------------------------------------------------- Our sensitivity to changes in interest rates is based on 2006 estimated average floating rate debt of $380 million and a Canadian/US dollar exchange rate of 85(cents). Our floating rate debt exposes us to changes in interest payments as interest rates fluctuate. To manage this exposure, we maintain a combination of fixed and floating rate borrowings and facilities. At December 31, 2005 fixed-rate borrowings comprised 95% (2004--56%) of our long-term debt at an effective average rate of 6.3% (2004--6.6%). During the year we periodically drew on our unsecured syndicated term credit facilities and at December 31, 2005, floating rate debt comprised nil (2004--44%) of our long-term debt at an effective average rate of 4.4% (2004--3.2%). We had no interest rate swaps outstanding in 2005 or 2004. TRADING COMMODITY PRICE RISK Our marketing operation is involved in the marketing and trading of crude oil, natural gas, natural gas liquids and power through the use of physical purchase and sales contracts as well as financial commodity contracts. These activities expose us to commodity price risk. The marketing operation actively manages this risk by utilizing energy-related futures, forwards, swaps and options, and generally attempts to balance its physical and financial contracts in terms of contract volumes and timing of performance and delivery obligations. However, net open positions may exist or may be established to take advantage of existing market conditions. Open positions exist where not all contracted purchases and sales have been matched. These net open positions allow us to generate income, but also expose us to risk of loss due to fluctuating market prices (market risk). Open positions and derivative instruments expose us to other risks, including credit risk and the risk of margin calls from third parties. The inability to close out options, futures and forward positions could have an adverse impact on the use of derivative instruments to effectively hedge our portfolio and/or generate income from marketing activities. We control the level of market risk through daily monitoring of our energy-trading portfolio relative to: o prescribed limits for Value-at-Risk (VaR); o nominal size of commodity positions; 66 o stop loss limits; and o stress testing. VaR is a statistical estimate that is reliable when normal market conditions prevail. Our VaR calculation estimates the maximum probable loss given a 95% confidence level that we would incur if we were to unwind our outstanding positions over a two-day period. We estimate VaR using the Variance-Covariance method based on historical commodity price volatility and correlation inputs. Our estimate is based upon the following key assumptions: o changes in commodity prices are normally distributed; o price volatility remains stable; and o price correlation relationships remain stable. If a severe market shock occurred, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. There were no changes in the methodology we used to estimate VaR in 2005. However, based on our assessment of risk measurements, we have removed VaR relating to credit from our total VaR and we review this separately. For 2005, VaR relating to credit ranged between $3 million and $5 million. Stress testing complements our VaR estimate. It is used to ensure that we are not exposed to large losses, not captured by VaR, which might result from infrequent but extreme market conditions. Our year-end, annual high, annual low and annual average VaR amounts are as follows: ------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------- Value at Risk ------------------------------------------------------------------------------- Year-End 24 21 21 ------------------------------------------------------------------------------- High 28 42 31 ------------------------------------------------------------------------------- Low 11 17 14 ------------------------------------------------------------------------------- Average 21 29 20 ------------------------------------------------------------------------------- Our Board of Directors has approved formal risk management policies for our energy trading activities. Market and credit risks are monitored daily by a risk group that operates independently and ensures compliance with our risk management policies. The Finance Committee of the Board of Directors and our Risk Management Committee monitor our exposure to the above risks and review the results of our energy trading activities regularly. CREDIT RISK Credit risk affects both our trading and non-trading activities and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposures are with counterparties in the oil and gas and energy trading industry and are subject to normal industry credit risk. We take the following measures to reduce this risk: o we assess the financial strength of our counterparties through a rigorous credit process; o we limit the total exposure extended to individual counterparties, and may require collateral from some counterparties; o we routinely monitor credit risk exposures, including sector, geographic and corporate concentrations of credit, and report these to our Risk Management Committee and the Finance Committee of the Board; o we set credit limits based on rating agency credit ratings and internal assessments based on company and industry analysis; o we review counterparty credit limits regularly; and o we use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe these measures minimize our overall credit risk. However, there can be no assurance that these processes will protect us against all losses from non-performance. At December 31, 2005: o over 97% of our credit exposures were investment grade; and o only two counterparties individually made up more than 5% of our credit exposure. Both were investment grade. 67 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements in this report, including those appearing in Items 1 and 2--Business and Properties and Item 7--Management's Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements (1). Forward-looking statements are generally identifiable by terms such as anticipate, believe, intend, plan, expect, estimate, budget, outlook or other similar words, and include statements relating to future production associated with our Coal Bed Methane, Long Lake, Syncrude, North Sea and West Africa projects and future capital investment plans. These statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. These risks, uncertainties and other factors include, among others: o market prices for oil, natural gas and chemicals products; o our ability to explore, develop, produce and transport crude oil and natural gas to markets; o the results of exploration and development drilling and related activities; o foreign-currency exchange rates; o economic conditions in the countries and regions in which we carry on business; o governmental actions that increase taxes, change environmental and other laws and regulations; o renegotiations of contracts; and o political uncertainty, including actions by insurgent or other armed groups or other conflict, including conflict between states. The above items and their possible impact are discussed more fully in the section, titled Business Risk Management in Item 7 and Quantitative and Qualitative Disclosures about Market Risk in Item 7A. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and management's future course of action depends upon our assessment of all information available at that time. Any statements regarding the following are forward-looking statements: o future crude oil, natural gas or chemicals prices; o future production levels; o future cost recovery oil revenues from our operations in Yemen; o future capital expenditures and their allocation to exploration and development activities; o future asset dispositions; o future sources of funding for our capital program; o possible commerciality, development plans or capacity expansions; o future ability to execute dispositions of assets or businesses; o future debt levels; o future cash flows and their uses; o future drilling of new wells; o ultimate recoverability of reserves; o expected finding and development costs; o expected operating costs; o future demand for chemicals products; o future expenditures and future allowances relating to environmental matters; and o dates by which certain areas will be developed or will come on stream. We believe that any forward-looking statements made are reasonable based on information available to us on the date such statements were made. However, no assurance can be given as to future results, levels of activity and achievements. Except to the extent required by law, we undertake no obligation to update publicly or revise any forward-looking statements contained in this report. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. (1) Within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. 68 SPECIAL NOTE TO CANADIAN INVESTORS Nexen is an SEC registrant and a Form 10-K and related forms filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In 2003, Canadian regulatory authorities adopted National Instrument 51-101--Standards of Disclosure for Oil and Gas Activities (NI 51-101) which prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. We have been granted the following exemptions permitting us to: o substitute our SEC disclosures for much of the annual disclosure required by NI 51-101; o prepare our reserves estimates and related disclosures in accordance with SEC requirements, generally accepted industry practices in the US and the standards of the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) modified to reflect SEC requirements; o dispense with the requirement to have our reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, evaluated or audited by independent qualified reserves evaluators; and o not disclose certain prescribed information pertaining to prospects if such disclosures would result in the contravention of a legal obligation, would likely be detrimental to our competitive interests or the information does not exist. As a result of these exemptions, Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained in the Form 10-K: o SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook; o the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using year-end constant prices and costs only whereas NI 51-101 also requires disclosure of reserves and related future net revenues using forecast prices; o the SEC mandates disclosure of proved and proved developed reserves by geographic region only whereas NI 51-101 requires disclosure of more reserve categories and product types; o the SEC does not prescribe the nature of the information required in connection with proved undeveloped reserves and future development costs whereas NI 51-101 requires certain detailed information regarding proved undeveloped reserves, related development plans and future development costs; o the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe be disclosed. NI 51-101 requires that F&D costs be calculated by dividing the aggregate of exploration and development costs incurred in the current year and the change in estimated future development costs relating to proved reserves by the additions to proved reserves in the current year. However, this will generally not reflect full cycle finding and development costs related to reserve additions for the year; o the SEC leaves the engagement of independent qualified reserves evaluators to the discretion of a company's board of directors whereas NI 51-101 requires issuers to engage such evaluators and to file their reports; o the SEC does not consider the upgrading component of our integrated oil sands project at Long Lake as an oil and gas activity, and therefore permits recognition of bitumen reserves only. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits recognition of synthetic reserves. Given high natural gas prices and wide light/heavy differentials at year end, we have not recognized any proved bitumen reserves under SEC requirements whereas under NI 51-101 we would have recognized 200 million barrels of proved synthetic reserves (before royalties); and o the SEC considers our Syncrude operation as a mining activity rather than an oil and gas activity, and therefore does not permit related reserves to be included with oil and gas reserves. NI 51-101 specifically includes such activity as an oil and gas activity and recognizes synthetic oil as a product type, and therefore permits them to be included with oil and gas reserves. We have provided a separate table showing our share of the Syncrude proved reserves as well as the additional disclosures relating to mining activities required by SEC requirements. The foregoing is a general description of the principal differences only. NI 51-101 requires that we make the following disclosures: o we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. 69 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page REPORT OF MANAGEMENT ........................................................71 REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS ......................72 CONSOLIDATED FINANCIAL STATEMENTS Consolidated Statement of Income ........................................73 Consolidated Balance Sheet ..............................................74 Consolidated Statement of Cash Flows ....................................75 Consolidated Statement of Shareholders' Equity ..........................76 Notes To Consolidated Financial Statements ..............................77 SUPPLEMENTARY DATA (UNAUDITED) Quarterly Financial Data In Accordance with Canadian and US GAAP .......116 Oil And Gas Producing Activities and Syncrude Operations ...............117 70 REPORT OF MANAGEMENT February 7, 2006 To the Shareholders of Nexen Inc.: We are responsible for the preparation and fair presentation of the consolidated financial statements, as well as the financial reporting process that gives rise to such consolidated financial statements. This responsibility requires us to make significant accounting judgments and estimates. For example, we are required to choose accounting principles and methods that are appropriate to the company's circumstances, and we are required to make estimates and assumptions that affect amounts reported. Fulfilling this responsibility requires the preparation and presentation of our consolidated financial statements in accordance with generally accepted accounting principles in Canada with a reconciliation to generally accepted accounting principles in the US. We also have responsibility for the preparation and fair presentation of other financial information in this report and to ensure the consistency of this information with the financial statements. We are responsible for the development and implementation of internal controls over the financial reporting process. These controls are designed to provide reasonable assurance that relevant and reliable financial information is produced. To gather and control financial data, we have established accounting and reporting systems supported by internal controls over financial reporting and an internal audit program. We believe that our internal controls over financial reporting provide reasonable assurance that our assets are safeguarded against loss from unauthorized use or disposition, that receipts and expenditures of the company are made only in accordance with authorization of management and directors of the company, and that our records are reliable for preparing our consolidated financial statements and other financial information in accordance with applicable generally accepted accounting principles and in accordance with applicable securities rules and regulations. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. We have established disclosure controls and procedures, internal controls over financial reporting and corporate-wide policies to ensure that Nexen's consolidated financial position, results of operations and cash flows are presented fairly. Our disclosure controls and procedures are designed to ensure timely disclosure and communication of all material information required by regulators. We oversee, with assistance from our Disclosure Review Committee, these controls and procedures and all required regulatory disclosures. To ensure the integrity of our financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization and include a written ethics and integrity policy that applies to all employees, including the chief executive officer, chief financial officer and chief accounting officer or controller. Our Board of Directors is responsible for reviewing and approving the consolidated financial statements and for overseeing management's performance of its financial reporting responsibilities. Their financial statement related responsibilities are fulfilled mainly through the Audit and Conduct Review Committee (the Audit Committee) with assistance from the Reserves Review Committee regarding the annual review of our crude oil and natural gas reserves and the Finance Committee regarding the assessment and mitigation of risk. The Audit Committee is composed entirely of independent directors and includes four directors with financial expertise. The Audit Committee meets regularly with management, the internal auditors and the independent registered Chartered Accountants (independent auditors) to review accounting policies, financial reporting and internal control issues and to ensure each party is properly discharging its responsibilities. The Audit Committee is responsible for the appointment and compensation of the independent auditors and also considers their independence, reviews their fees and (subject to applicable securities laws), pre-approves their retention for any permitted non-audit services and their fee for such services. The internal auditors and independent auditors have full and unlimited access to the Audit Committee, with or without the presence of management. /s/ Charles W. Fischer /s/ Marvin F. Romanow -------------------------------- ------------------------------- President and Chief Executive Executive Vice President and Officer Chief Financial Officer 71 REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS To the Board of Directors and Shareholders of Nexen Inc.: We have audited the consolidated balance sheets of Nexen Inc. as at December 31, 2005 and 2004 and the consolidated statements of income, cash flows and shareholders' equity for each of the years in the three year period ended December 31, 2005. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of Nexen Inc. as at December 31, 2005 and 2004 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2005 in accordance with Canadian generally accepted accounting principles. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as at December 31, 2005, based on the criteria established in Internal Control--Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 7, 2006 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting. Calgary, Canada /s/ Deloitte & Touche LLP February 7, 2006 Independent Registered Chartered Accountants COMMENTS BY AUDITORS ON CANADA-UNITED STATES OF AMERICA REPORTING DIFFERENCE The standards of the Public Company Accounting Oversight Board (United States) require the addition of an explanatory paragraph (following the opinion paragraph) when there are changes in accounting principles that have a material effect on the comparability of the Company's financial statements, such as the changes described in Note 1(u) to the consolidated financial statements. Our report to the board of directors and shareholders on the consolidated financial statements of Nexen Inc., dated February 7, 2006, is expressed in accordance with Canadian reporting standards which do not require a reference to such changes in accounting principles in the auditors' report when the change is properly accounted for and adequately disclosed in the financial statements. Calgary, Canada /s/ Deloitte & Touche LLP February 7, 2006 Independent Registered Chartered Accountants 72
NEXEN INC. CONSOLIDATED STATEMENT OF INCOME FOR THE THREE YEARS ENDED DECEMBER 31, 2005 -------------------------------------------------------------------------------------------------------------- Cdn$ million, except per share amounts 2005 2004 2003 -------------------------------------------------------------------------------------------------------------- Net Sales 3,932 2,944 2,632 -------------------------------------------------------------------------------------------------------------- Marketing and Other (Note 17) 702 713 610 -------------------------------------------------------------------------------------------------------------- Gain on Dilution of Interest in Chemicals Business (Note 2) 193 - - -------------------------------------------------------------------------------------------------------------- 4,827 3,657 3,242 -------------------------------------------------------------------------------------------------------------- Expenses -------------------------------------------------------------------------------------------------------------- Operating 893 722 688 -------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment (Note 6) 1,052 674 914 -------------------------------------------------------------------------------------------------------------- Transportation and Other 796 549 489 -------------------------------------------------------------------------------------------------------------- General and Administrative 792 299 185 -------------------------------------------------------------------------------------------------------------- Exploration 250 243 193 -------------------------------------------------------------------------------------------------------------- Interest (Note 8) 97 143 169 -------------------------------------------------------------------------------------------------------------- 3,880 2,630 2,638 -------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Taxes 947 1,027 604 -------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------- Provision for Income Taxes (Note 18) -------------------------------------------------------------------------------------------------------------- Current 339 248 214 -------------------------------------------------------------------------------------------------------------- (100) 69 (117) Future -------------------------------------------------------------------------------------------------------------- 239 317 97 -------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations before Non-Controlling Interests 708 710 507 -------------------------------------------------------------------------------------------------------------- Net Income Attributable to Non-Controlling 8 - - Interests -------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations 700 710 507 -------------------------------------------------------------------------------------------------------------- Net Income from Discontinued Operations (Note 14) 452 83 71 -------------------------------------------------------------------------------------------------------------- Net Income 1,152 793 578 -------------------------------------------------------------------------------------------------------------- Earnings Per Common Share from Continuing Operations ($/share) -------------------------------------------------------------------------------------------------------------- Basic (Note 13) 2.69 2.76 2.05 -------------------------------------------------------------------------------------------------------------- Diluted (Note 13) 2.63 2.72 2.03 -------------------------------------------------------------------------------------------------------------- Earnings Per Common Share ($/share) -------------------------------------------------------------------------------------------------------------- Basic (Note 13) 4.43 3.08 2.33 -------------------------------------------------------------------------------------------------------------- Diluted (Note 13) 4.33 3.04 2.31 --------------------------------------------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements. 73 NEXEN INC. CONSOLIDATED BALANCE SHEET DECEMBER 31, 2005 AND 2004 ------------------------------------------------------------------------------- Cdn$ million, except share amounts 2005 2004 ------------------------------------------------------------------------------- ASSETS ------------------------------------------------------------------------------- Current Assets ------------------------------------------------------------------------------- Cash and Cash Equivalents 48 73 ------------------------------------------------------------------------------- Restricted Cash 70 - ------------------------------------------------------------------------------- Accounts Receivable (Note 4) 3,151 2,100 ------------------------------------------------------------------------------- Inventories and Supplies (Note 5) 504 351 ------------------------------------------------------------------------------- Assets of Discontinued Operations (Note 14) - 38 ------------------------------------------------------------------------------- Other 51 41 ------------------------------------------------------------------------------- Total Current Assets 3,824 2,603 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Property, Plant and Equipment (Note 6) 9,594 8,203 ------------------------------------------------------------------------------- Goodwill 364 375 ------------------------------------------------------------------------------- Future Income Tax Assets (Note 18) 410 333 ------------------------------------------------------------------------------- Deferred Charges and Other Assets (Note 10) 398 429 ------------------------------------------------------------------------------- Assets of Discontinued Operations (Note 14) - 440 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- TOTAL ASSETS 14,590 12,383 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- LIABILITIES AND SHAREHOLDERS' EQUITY ------------------------------------------------------------------------------- Current Liabilities ------------------------------------------------------------------------------- Short-Term Borrowings (Note 8) - 100 ------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities 3,710 2,377 ------------------------------------------------------------------------------- Accrued Interest Payable 55 34 ------------------------------------------------------------------------------- Dividends Payable 13 13 ------------------------------------------------------------------------------- Liabilities of Discontinued Operations (Note 14) - 39 ------------------------------------------------------------------------------- Total Current Liabilities 3,778 2,563 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Long-Term Debt (Note 8) 3,687 4,259 ------------------------------------------------------------------------------- Future Income Tax Liabilities (Note 18) 1,960 2,023 ------------------------------------------------------------------------------- Asset Retirement Obligations (Note 9) 590 399 ------------------------------------------------------------------------------- Deferred Credits and Other Liabilities (Note 11) 479 142 ------------------------------------------------------------------------------- Liabilities of Discontinued Operations (Note 14) - 130 ------------------------------------------------------------------------------- Non-Controlling Interests (Note 2) 88 - ------------------------------------------------------------------------------- Shareholders' Equity (Note 12) ------------------------------------------------------------------------------- Common Shares, no par value ------------------------------------------------------------------------------- Authorized: Unlimited ------------------------------------------------------------------------------- Outstanding: 2005--261,140,571 shares ------------------------------------------------------------------------------- 2004--258,399,166 shares 732 637 ------------------------------------------------------------------------------- Contributed Surplus 2 - ------------------------------------------------------------------------------- Retained Earnings 3,435 2,335 ------------------------------------------------------------------------------- Cumulative Foreign Currency Translation Adjustment (161) (105) ------------------------------------------------------------------------------- Total Shareholders' Equity 4,008 2,867 ------------------------------------------------------------------------------- Commitments, Contingencies and Guarantees (Notes 15 and 18) ------------------------------------------------------------------------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 14,590 12,383 ------------------------------------------------------------------------------- See accompanying notes to Consolidated Financial Statements. Approved on behalf of the Board: /s/ Charles W. Fischer /s/ Thomas C. O'Neill ------------------------- ----------------------- Director Director 74 NEXEN INC. CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE THREE YEARS ENDED DECEMBER 31, 2005
------------------------------------------------------------------------------------------------------------------- Cdn$ millions 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------- Operating Activities ------------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations 700 710 507 ------------------------------------------------------------------------------------------------------------------- Net Income from Discontinued Operations 452 83 71 ------------------------------------------------------------------------------------------------------------------- Charges and Credits to Income not Involving Cash (Note 19) 1,069 906 1,024 ------------------------------------------------------------------------------------------------------------------- Exploration Expense 250 243 193 ------------------------------------------------------------------------------------------------------------------- Changes in Non-Cash Working Capital (Note 19) (195) (122) (320) ------------------------------------------------------------------------------------------------------------------- Other (133) (214) (70) ------------------------------------------------------------------------------------------------------------------- 2,143 1,606 1,405 ------------------------------------------------------------------------------------------------------------------- Financing Activities ------------------------------------------------------------------------------------------------------------------- Proceeds from Long-Term Notes and Debentures (Note 8) 1,253 1,779 651 ------------------------------------------------------------------------------------------------------------------- Repayment of Long-Term Notes and Debentures (Note 8) (1,818) (300) - ------------------------------------------------------------------------------------------------------------------- Proceeds from (Repayment of) Term Credit Facilities, Net (66) 83 93 ------------------------------------------------------------------------------------------------------------------- Proceeds from (Repayment of) Short-Term Borrowings, Net (99) 101 (18) ------------------------------------------------------------------------------------------------------------------- Proceeds from Subordinated Debentures (Note 8) - - 613 ------------------------------------------------------------------------------------------------------------------- Redemption of Preferred Securities - (289) (340) ------------------------------------------------------------------------------------------------------------------- Dividends on Common Shares (52) (52) (40) ------------------------------------------------------------------------------------------------------------------- Issue of Common Shares 58 124 73 ------------------------------------------------------------------------------------------------------------------- Net Proceeds from Canexus Initial Public Offering (Note 2) 301 - - ------------------------------------------------------------------------------------------------------------------- Proceeds from Term Credit Facilities of Canexus, Net (Notes 2 and 8) 176 - - ------------------------------------------------------------------------------------------------------------------- Other (27) (20) (26) ------------------------------------------------------------------------------------------------------------------- (274) 1,426 1,006 ------------------------------------------------------------------------------------------------------------------- Investing Activities ------------------------------------------------------------------------------------------------------------------- Business Acquisition, Net of Cash Acquired (Note 3) - (2,583) - ------------------------------------------------------------------------------------------------------------------- Capital Expenditures ------------------------------------------------------------------------------------------------------------------- Exploration and Development (2,564) (1,582) (1,276) ------------------------------------------------------------------------------------------------------------------- Proved Property Acquisitions (20) (4) (164) ------------------------------------------------------------------------------------------------------------------- Chemicals, Corporate and Other (54) (95) (54) ------------------------------------------------------------------------------------------------------------------- Proceeds on Disposition of Assets 911 34 293 ------------------------------------------------------------------------------------------------------------------- Changes in Non-Cash Working Capital (Note 19) (54) 244 (18) ------------------------------------------------------------------------------------------------------------------- Changes in Restricted Cash (70) - - ------------------------------------------------------------------------------------------------------------------- Other (13) (27) - ------------------------------------------------------------------------------------------------------------------- (1,864) (4,013) (1,219) ------------------------------------------------------------------------------------------------------------------- Effect of Exchange Rate Changes on Cash and Cash Equivalents (30) (33) (164) ------------------------------------------------------------------------------------------------------------------- Increase (Decrease) in Cash and Cash Equivalents (25) (1,014) 1,028 ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents--Beginning of Year 73 1,087 59 ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents--End of Year 48 73 1,087 -------------------------------------------------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements. 75 NEXEN INC. CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY FOR THE THREE YEARS ENDED DECEMBER 31, 2005
--------------------------------------------------------------------------------------------------------------- Cdn$ millions 2005 2004 2003 --------------------------------------------------------------------------------------------------------------- Common Shares (Note 12) --------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year 637 513 440 --------------------------------------------------------------------------------------------------------------- Exercise of Stock Options 29 93 50 --------------------------------------------------------------------------------------------------------------- Issue of Common Shares 29 31 23 --------------------------------------------------------------------------------------------------------------- Previously Recognized Liability Relating to Stock Options Exercised 37 - - --------------------------------------------------------------------------------------------------------------- Balance at End of Year 732 637 513 --------------------------------------------------------------------------------------------------------------- Contributed Surplus --------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year - 1 - --------------------------------------------------------------------------------------------------------------- Stock Based Compensation Expense (Note 12) 2 2 1 --------------------------------------------------------------------------------------------------------------- Modification of Stock Option Plan to Tandem Option Plan (Note 12) - (3) - --------------------------------------------------------------------------------------------------------------- Balance at End of Year 2 - 1 --------------------------------------------------------------------------------------------------------------- Retained Earnings --------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year 2,335 1,594 1,056 --------------------------------------------------------------------------------------------------------------- Net Income 1,152 793 578 --------------------------------------------------------------------------------------------------------------- Dividends on Common Shares (52) (52) (40) --------------------------------------------------------------------------------------------------------------- Balance at End of Year 3,435 2,335 1,594 --------------------------------------------------------------------------------------------------------------- Cumulative Foreign Currency Translation Adjustment --------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year (105) (33) 94 --------------------------------------------------------------------------------------------------------------- Translation Adjustment, Net of Income Taxes (56) (72) (127) --------------------------------------------------------------------------------------------------------------- Balance at End of Year (161) (105) (33) ---------------------------------------------------------------------------------------------------------------
See accompanying notes to Consolidated Financial Statements. 76 NEXEN INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Cdn$ millions except as noted 1. ACCOUNTING POLICIES Our Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States (US) GAAP on the Consolidated Financial Statements is disclosed in Note 21. (a) USE OF ESTIMATES We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates, including those related to accruals, litigation, environmental and asset retirement obligations, income taxes and the determination of proved reserves on an ongoing basis. Changes in facts and circumstances may result in revised estimates, and actual results may differ from these estimates. (b) PRINCIPLES OF CONSOLIDATION The Consolidated Financial Statements include the accounts of Nexen Inc. and our subsidiary companies (Nexen, we or our). All subsidiary companies, with the exception of Canexus LP (see Note 2) and its subsidiaries, are wholly owned and all material intercompany accounts and transactions have been eliminated. On August 18, 2005, we sold our chemicals operations to Canexus LP, but retained effective control of these operations through our 61.4% interest in Canexus LP (see Note 2). All of the assets, liabilities and results of operations of Canexus LP and its subsidiaries have been included in our consolidated financial statements. The non-Nexen ownership interests in Canexus LP and its subsidiaries are shown as non-controlling interests. We proportionately consolidate our undivided interests in our oil and gas exploration, development and production activities conducted under joint venture arrangements. We also proportionately consolidate our 7.23% undivided interest in the Syncrude joint venture, which is considered a mining activity under US regulations. While the joint ventures under which these activities are carried out do not comprise distinct legal entities, they are operating entities, the significant operating policies of which are, by contractual arrangement, jointly controlled by all working interest parties. (c) ACCOUNTS RECEIVABLE Accounts receivable are recorded based on our revenue recognition policy (see Note 1(j)). Our allowance for doubtful accounts provides for specific doubtful receivables. (d) INVENTORIES AND SUPPLIES Inventories and supplies for our oil and gas, marketing and chemicals operations are stated at the lower of cost and net realizable value. Cost is determined on the first-in, first-out method or average basis. Inventory costs include expenditures and other costs, including depreciation, depletion and amortization, directly or indirectly incurred in bringing the inventory to its existing condition. (e) PROPERTY, PLANT AND EQUIPMENT (PP&E) Property, plant and equipment is recorded at cost and includes only recoverable costs that directly result in an identifiable future benefit. Unrecoverable costs, maintenance and turnaround costs are expensed as incurred. Improvements that increase capacity or extend the useful lives of the related assets are capitalized to PP&E. We follow successful efforts accounting for our oil and gas business. All property acquisition costs are initially capitalized to PP&E as unproved property costs. Once proved reserves are discovered, the acquisition costs are reclassified to proved property acquisition costs. Exploration drilling costs are capitalized pending evaluation as to whether sufficient quantities of reserves have been found to justify commercial production. If commercial quantities of reserves are not found, exploration drilling costs are expensed. All exploratory wells are evaluated for commercial viability on a regular basis following completion of drilling. Exploration drilling costs remain capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made to assess the reserves and the economic and operating viability of the well. All other exploration costs, including geological and geophysical and annual lease rentals, are expensed to earnings as incurred. All development costs are capitalized as proved property costs. General and administrative costs that directly relate to acquisition, exploration and development activities are capitalized to PP&E. 77 PP&E for our Syncrude operation is recorded at cost and includes only recoverable costs that directly result in an identifiable future benefit. Unrecoverable costs, maintenance and turnaround costs are expensed as incurred. Improvements that increase capacity or extend the useful lives of the related assets are capitalized to PP&E. We engage in research and development activities to develop or improve processes and techniques to extract oil and gas. Research involves investigating new knowledge. Development involves translating that knowledge into a new technology or process. Research costs are expensed as incurred. Development costs are deferred once technical feasibility is established, and we intend to proceed with development. We defer these costs in PP&E until the commencement of commercial operations or production. Otherwise, development costs are expensed as incurred. Development costs include pre-operating revenues and costs. (f) DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT (DD&A) Under successful efforts accounting, we deplete oil and gas capitalized costs using the unit-of-production method. Development and exploration drilling and equipping costs are depleted over remaining proved developed reserves and proved property acquisition costs over remaining proved reserves. Depletion is considered a cost of inventory when the oil and gas is produced. When this inventory is sold, the depletion is charged to DD&A expense. Our Syncrude PP&E is depleted using the unit-of-production method. Capitalized costs are depleted over proved and probable reserves within developed areas of interest. We depreciate other plant and equipment costs, including our chemicals facilities, using the straight-line method based on the estimated useful lives of the assets, which range from 3 years to 30 years. Unproved property costs and major projects that are under construction or development are not depreciated, depleted or amortized. We evaluate the carrying value of our PP&E whenever events or conditions occur that indicate that the carrying value of properties on our balance sheet may not be recoverable from future cash flows. These events or conditions occur periodically. If carrying value exceeds the sum of undiscounted future cash flows, the property's value is impaired. The property is then assigned a fair value equal to its estimated total future cash flows, discounted for the time value of money, and we expense the excess carrying value to depreciation, depletion, amortization and impairment. Our cash flow estimates require assumptions about future commodity prices, operating costs and other factors. Actual results can differ from these estimates. In assessing the carrying values of our unproved properties, we take into account our future plans for these properties, the remaining terms of the leases and any other factors that may be indicators of potential impairment. (g) CARRIED INTEREST We conduct certain international operations jointly with foreign governments in accordance with production sharing agreements pursuant to which proved reserves are recognized using the economic interest method. Under these agreements, we pay both our share and the government's share of operating and capital costs. We recover the government's share of these costs from future revenues or production over several years. The government's share of operating costs are recorded in operating expense when incurred and capital costs are recorded in PP&E and expensed to DD&A in the year recovered. All recoveries are recorded as revenue in the year of recovery. (h) ASSET RETIREMENT OBLIGATIONS We provide for future asset retirement obligations on our resource properties, facilities, production platforms, pipelines and chemicals facilities based on estimates established by current legislation and industry practices. The asset retirement obligation is initially measured at fair value and capitalized to PP&E as an asset retirement cost. The asset retirement obligation accretes until the time the retirement obligation is expected to settle, while the asset retirement cost is amortized over the useful life of the underlying PP&E. We periodically review our estimates for changes in expected amounts or timing of cash flows. The amortization of the asset retirement cost and the accretion of the asset retirement obligation are included in depreciation, depletion, amortization and impairment. Actual retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligation and the actual retirement costs incurred is recorded as a gain or loss in the period of settlement. 78 (i) GOODWILL Goodwill is recorded at cost and is not amortized. We test goodwill for impairment annually based on estimated future cash flows of the reporting unit to which the goodwill is attributable. In addition, we test goodwill for impairment whenever an event or circumstance occurs that may reduce the fair value of a reporting unit below its carrying amount. If our goodwill is impaired, we write it down to its implied fair value, based on the fair value of the assets and liabilities of the underlying reporting unit. Our goodwill is attributable to our marketing and UK reporting units. (j) REVENUE RECOGNITION CRUDE OIL AND NATURAL GAS Revenue from the production of crude oil and natural gas is recognized when title passes to the customer. In Canada, the US and the UK, our customers primarily take title when the crude oil and natural gas reaches the end of the pipeline. For our other international operations, our customers take title when the crude oil is loaded onto the tanker. When we produce or sell more or less oil or natural gas than our share, production overlifts and underlifts occur. We record overlifts as liabilities and underlifts as assets. We settle these over time as liftings are equalized or in cash when production ends. Revenue represents Nexen's share and is recorded net of royalty payments to governments and other mineral interest owners. For our international operations, all government interests, except for income taxes, are considered royalty payments. Our revenue also includes the recovery of costs paid on behalf of foreign governments in international locations. See Note 1(g). CHEMICALS Revenue from our chemicals operations is only recognized when our products are delivered to our customers. Delivery only takes place when we have a sales contract in place specifying delivery volumes and sales prices. We assess customer credit worthiness before entering into sales contracts to minimize collection risk. MARKETING Substantially all of the physical purchase and sales contracts entered into by our marketing operation are considered to be derivative instruments. Accordingly, financial and physical commodity contracts (collectively derivative instruments) held by our marketing operation are stated at fair value on the balance sheet unless the requirements for hedge accounting are met (see Note 1(n)). We record any change in fair value as a gain or loss in marketing and other. Any margin realized by our marketing operation on the sale of our proprietary oil and gas production is included in marketing and other. We assess customer credit worthiness before entering into contracts and provide for netting terms to minimize collection risk. Amounts are recorded on a net basis where we have the legal right of offset. Our marketing operation has received cash payments in exchange for assuming certain transportation obligations from third parties. These cash payments have been recorded as deferred liabilities and are recognized in net income as the transportation is used. (k) INCOME TAXES We follow the liability method of accounting for income taxes (see Note 18). This method recognizes income tax assets and liabilities at current rates, based on temporary differences in reported amounts for financial statement and tax purposes. The effect of a change in income tax rates on future income tax assets and future income tax liabilities is recognized in income when substantively enacted. We do not provide for foreign withholding taxes on the undistributed earnings of our foreign subsidiaries, as we intend to invest such earnings indefinitely in foreign operations. (l) FOREIGN CURRENCY TRANSLATION Our foreign operations, which are considered financially and operationally independent, are translated from their functional currency into Canadian dollars as follows: o assets and liabilities using exchange rates at the balance sheet dates; and o revenues and expenses using average exchange rates throughout the year. Gains and losses resulting from this translation are included in the cumulative foreign currency translation adjustment in shareholders' equity. 79 Monetary balances denominated in a currency other than a functional currency are translated into the functional currency using exchange rates at the balance sheet dates. Gains and losses arising from this translation, except on our designated US-dollar debt, are included in income. We have designated our US-dollar debt as a hedge against our net investment in US-dollar based self-sustaining foreign operations. Gains and losses resulting from the translation of the designated US-dollar debt are included in the cumulative foreign currency translation adjustment in shareholders' equity. If our US-dollar debt, net of income taxes, exceeds our US-dollar investment in foreign operations, then the gains or losses attributable to such excess are included in marketing and other in the Consolidated Statement of Income. (m) CAPITALIZED INTEREST We capitalize interest on major development projects until the project is substantially complete using the weighted-average interest rate on all of our borrowings. Capitalized interest cannot exceed the actual interest expense. (n) DERIVATIVE INSTRUMENTS NON-TRADING ACTIVITIES We use derivative instruments such as physical purchase and sales contracts, forwards, futures, swaps and options for non-trading purposes to manage fluctuations in commodity prices, foreign currency exchange rates and interest rates (see Note 7). We record these instruments at fair value at the balance sheet date and record any change in fair value as a net gain or loss in marketing and other during the period of change unless the requirements for hedge accounting are met. Hedge accounting is used when there is a high degree of correlation between price movements in the derivative instruments and the items designated as being hedged. Nexen formally documents all hedges and the risk management objectives at the inception of the hedge. We recognize gains and losses on the derivative instruments designated as hedges in the same period as the gains or losses on the hedged items are recognized. If effective correlation ceases, hedge accounting is terminated, and future changes in the market value of the derivative instrument are included as gains or losses in marketing and other in the period of change. TRADING ACTIVITIES Our marketing operation uses derivative instruments for marketing and trading crude oil and natural gas including: o commodity contracts settled with physical delivery; o exchange-traded futures and options; and o non-exchange traded forwards, swaps and options. We record these instruments at fair value at the balance sheet date and record changes in fair value as net gains or losses in marketing and other during the period of change. The fair value of these instruments is recorded as accounts receivable or payable if we anticipate settling the instruments within a year of the balance sheet date. If we anticipate settling the instruments beyond 12 months, we record them as deferred charges and other assets or deferred credits and other liabilities. (o) EMPLOYEE FUTURE BENEFITS The cost of pension benefits earned by employees in our defined benefit pension plans is actuarially determined using the projected-benefit method prorated on service and our best estimate of the plans' investment performance, salary escalations and retirement ages of employees. To calculate the plans' expected returns, assets are measured at fair value. Past service costs arising from plan amendments, and net actuarial gains and losses that exceed 10% of the greater of the accrued benefit obligation and the fair value of plan assets, are expensed in equal amounts over the expected average remaining service life of the employee group. We measure the plan assets and the accrued benefit obligation on October 31 each year. (p) STOCK-BASED COMPENSATION In 2003, we adopted the fair-value method of accounting for stock options granted to employees and directors. We recorded stock-based compensation expense in the Consolidated Statement of Income as general and administrative expenses for all options granted on or after January 1, 2003, with a corresponding increase to contributed surplus. Compensation expense for options granted was based on estimated fair values at the time of grant and we recognized the expense over the vesting period of the option. 80 In May 2004, we modified our stock option plan to a tandem option plan by including a cash feature. The tandem options give the holders a right to either purchase common shares at the exercise price or to receive cash payments equal to the excess of the market value of the common shares over the exercise price. As a result of the modification, we record obligations for the tandem options using the intrinsic-value method of accounting and recognize compensation expense. Obligations are accrued on a graded vesting basis and represent the difference between the market value of our common shares and the exercise price of the options. The obligations are revalued each reporting period based on the change in the market value of our common shares and the number of graded vested options outstanding. We reduce the liability when the options are surrendered for cash. When the options are exercised for stock, the recorded liability amount is transferred to share capital. Stock options awarded to our US employees between December 1, 2004 and December 1, 2005 do not include a cash feature and are not accounted for as tandem options. Instead, we account for these options using the fair-value method. Compensation expense is based on estimated fair values at the time of grant and is recognized over the vesting period of the options. The expense is included as general and administrative expense with a corresponding increase to contributed surplus. Stock options awarded to our US employees after December 1, 2005 are accounted for as tandem options. We provide stock appreciation rights to employees as described in Note 12, and we account for these on the same basis as our tandem options. Obligations are accrued as compensation expense over the graded vesting period of the stock appreciation rights. (q) CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term, highly liquid investments that mature within three months of their purchase. They are recorded at cost, which approximates market value. (r) RESTRICTED CASH Restricted cash includes margin deposits relating to our exchange-traded derivative contracts and other cash balances subject to regulatory restrictions. (s) LEASES We classify leases entered into as either capital or operating leases. Leases that transfer substantially all of the benefits and risks of ownership to us are accounted for as capital leases and included with PP&E. These assets are depreciated on the same basis as other PP&E. Rental payments under operating leases are expensed as incurred. (t) TRANSPORTATION We pay to transport the crude oil, natural gas and chemicals products that we market, and then bill our customers for the transportation. This transportation is presented in our Consolidated Financial Statements as a cost to us and is recorded as transportation and other. (u) CHANGES IN ACCOUNTING PRINCIPLES FINANCIAL INSTRUMENTS In the fourth quarter of 2004, we retroactively adopted the changes to CICA standard S.3860, Financial Instruments. These changes require that fixed-amount contractual obligations that can be settled by issuing a variable number of equity instruments be classified as a liability. Our US-dollar denominated preferred and subordinated securities have these characteristics and accordingly have been reclassified as long-term debt. Dividends and interest on these securities have been included in interest expense, and issue costs previously charged to retained earnings have been amortized over the life of the securities. Unamortized issue costs have been expensed on the redemption of the preferred securities in 2003 and 2004. Foreign exchange gains or losses from translation of the US-dollar denominated preferred and subordinated securities have been included as cumulative foreign currency translation adjustments. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES In 2004, we adopted CICA standard S.1100, Generally Accepted Accounting Principles which eliminated general practice in Canada as a component of GAAP. Our accounting policy for 2005 and 2004 is to include geological and geophysical costs as operating cash outflows in our Consolidated Statement of Cash Flows. For previous years, we included geological and geophysical costs as investing cash outflows consistent with industry practice in Canada. In our Consolidated Statement of 81 Cash Flows for 2005 and 2004, we included $53 and $73 million, respectively, of geological and geophysical costs as other operating cash outflows. For 2003, geological and geophysical costs of $62 million are included in investing activities as exploration and development capital expenditures. This change in accounting policy was adopted prospectively. (v) RECLASSIFICATION Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2005. 2. CANEXUS INCOME FUND In June 2005, our board of directors approved a plan to monetize our chemicals operations through the creation of an income trust and the issuance of trust units in an initial public offering. This initial public offering closed on August 18, 2005, with Canexus Income Fund (Canexus) issuing 30 million units at a price of $10 per unit for gross proceeds of $300 million ($284 million, net of underwriters' commissions). Concurrent with the closing of the offering, Canexus acquired a 36.5% interest in Canexus Limited Partnership (Canexus LP) using the net proceeds from the initial public offering. Canexus LP acquired Nexen's chemicals business for approximately $1 billion, comprised of the net proceeds from Canexus' initial public offering and $200 million (US$167 million) of bank debt, plus the issuance of 52.3 million exchangeable limited partnership units (Exchangeable LP Units) of Canexus LP. At that time, the Exchangeable LP Units held by Nexen represented a 63.5% interest in Canexus LP. The Exchangeable LP Units held by Nexen are exchangeable on a one-for-one basis for trust units of Canexus. As a result, the Exchangeable LP Units owned by Nexen were exchangeable into 52.3 million trust units which represented 63.5% of the outstanding trust units of Canexus assuming exchange of the Exchangeable LP Units. On September 16, 2005, the underwriters of the initial public offering exercised a portion of their over-allotment option to purchase 1.75 million trust units at $10 per unit for gross proceeds of $18 million ($17 million, net of underwriters' commissions). As a result, Nexen exchanged 1.75 million of its Exchangeable LP Units for $17 million in net proceeds. After this exchange, Nexen has a 61.4% interest in Canexus LP represented by 50.5 million Exchangeable LP Units. The initial public offering, together with the exercise of the over-allotment, resulted in total net proceeds to Nexen of $301 million. These transactions diluted our interest in our chemicals operations. As a result of this dilution, we recorded a gain of $193 million during the third quarter of 2005. We have the right to nominate a majority of the members of the board of Canexus Limited, the corporation with responsibility for the strategic management and operational decisions of Canexus and Canexus LP. Nexen has nominated two representatives to the 10-member board of Canexus Limited. Since we have retained effective control of our chemicals business, the results, assets and liabilities of this business have been included in these financial statements. The non-Nexen ownership interests in our chemicals business are shown as non-controlling interests. 3. BUSINESS ACQUISITION On December 1, 2004, we acquired 100% of the issued and outstanding share capital of EnCana (UK) Limited (EnCana UK) from EnCana Corporation (EnCana) for cash consideration of US$2.1 billion, subject to certain adjustments. EnCana UK held all of EnCana's offshore oil and gas assets in the North Sea. We acquired EnCana UK to establish a strategic presence in the North Sea by acquiring operatorship of the Buzzard field development and operatorship of the producing Scott and Telford fields. The acquisition also gave us access to interests in several satellite discoveries and more than 700,000 net undeveloped exploration acres. In addition, we acquired the management and technical teams that found and are developing the Buzzard discovery. Goodwill paid was attributable to the established North Sea presence acquired and the knowledge and business relationships acquired through the management team and employees of EnCana UK. 82 The acquisition has been accounted for using the purchase method, and the results of EnCana UK have been consolidated with the results of Nexen from December 1, 2004. The following table shows the allocation of the purchase price based on the estimated fair values of the assets and liabilities acquired: ------------------------------------------------------------------------------ Purchase Price, Net of Cash Acquired: ------------------------------------------------------------------------------ Cash Paid 2,561 ------------------------------------------------------------------------------ Transaction Costs 22 ------------------------------------------------------------------------------ Total Purchase Price 2,583 ------------------------------------------------------------------------------ Purchase Price Allocated as follows: ------------------------------------------------------------------------------ Accounts Receivable 310 ------------------------------------------------------------------------------ Inventories and Supplies 11 ------------------------------------------------------------------------------ Other Current Assets 2 ------------------------------------------------------------------------------ Property, Plant and Equipment 3,395 ------------------------------------------------------------------------------ Future Income Tax Assets 239 ------------------------------------------------------------------------------ Goodwill (1) 334 ------------------------------------------------------------------------------ Deferred Charges and Other Assets 12 ------------------------------------------------------------------------------ Accounts Payable and Accrued Liabilities (289) ------------------------------------------------------------------------------ Asset Retirement Obligations (134) ------------------------------------------------------------------------------ Future Income Tax Liabilities (1,284) ------------------------------------------------------------------------------ Deferred Credits and Other Liabilities (13) ------------------------------------------------------------------------------ Total Purchase Price Allocated 2,583 ------------------------------------------------------------------------------ Note: (1) The amount of goodwill deductible for tax purposes is nil. The unaudited pro forma results for the years ended December 31, 2004 and 2003 are shown below as if the acquisition had occurred on January 1, 2003. Pro forma results are not necessarily indicative of actual results or future performance. ------------------------------------------------------------------------------ 2004 2003 ------------------------------------------------------------------------------ Revenues 4,258 3,642 ------------------------------------------------------------------------------ Net Income 841 595 ------------------------------------------------------------------------------ Earnings Per Common Share--Basic ($/share) 3.27 2.40 ------------------------------------------------------------------------------ Earnings Per Common Share--Diluted ($/share) 3.23 2.38 ------------------------------------------------------------------------------ 4. ACCOUNTS RECEIVABLE ------------------------------------------------------------------------------ 2005 2004 ------------------------------------------------------------------------------ Trade ------------------------------------------------------------------------------ Marketing 2,400 1,452 ------------------------------------------------------------------------------ Oil and Gas 614 557 ------------------------------------------------------------------------------ Chemicals and Other 48 57 ------------------------------------------------------------------------------ 3,062 2,066 ------------------------------------------------------------------------------ Non-Trade 96 49 ------------------------------------------------------------------------------ 3,158 2,115 ------------------------------------------------------------------------------ Allowance for Doubtful Receivables (7) (15) ------------------------------------------------------------------------------ Total Accounts Receivable 3,151 2,100 ------------------------------------------------------------------------------ 83 5. INVENTORIES AND SUPPLIES ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Finished Products ------------------------------------------------------------------------------- Marketing 320 199 ------------------------------------------------------------------------------- Oil and Gas 11 6 ------------------------------------------------------------------------------- Chemicals and Other 15 13 ------------------------------------------------------------------------------- 346 218 ------------------------------------------------------------------------------- Work in Process 6 4 ------------------------------------------------------------------------------- Field Supplies 152 129 ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- Total Inventories and Supplies 504 351 ------------------------------------------------------------------------------- 6. PROPERTY, PLANT AND EQUIPMENT
------------------------------------------------------------------------------------------------------------------ 2005 2004 ------------------------------------------------------------------------------------------------------------------ Accumulated Accumulated Net Book Net Book ------------------------------------------------------------------------------------------------------------------ Cost DD&A Value Cost DD&A Value ------------------------------------------------------------------------------------------------------------------ Oil and Gas ------------------------------------------------------------------------------------------------------------------ Yemen 833 546 287 678 506 172 ------------------------------------------------------------------------------------------------------------------ Yemen--Carried Interest 1,410 1,295 115 1,360 1,044 316 Interest ------------------------------------------------------------------------------------------------------------------ Canada 3,631 1,311 2,320 2,603 1,195 1,408 ------------------------------------------------------------------------------------------------------------------ United States 2,437 1,159 1,278 2,249 1,037 1,212 ------------------------------------------------------------------------------------------------------------------ United Kingdom 4,013 216 3,797 3,499 16 3,483 ------------------------------------------------------------------------------------------------------------------ Other Countries 249 119 130 535 408 127 ------------------------------------------------------------------------------------------------------------------ Marketing 177 72 105 157 64 93 ------------------------------------------------------------------------------------------------------------------ 12,750 4,718 8,032 11,081 4,270 6,811 ------------------------------------------------------------------------------------------------------------------ Syncrude 1,240 171 1,069 1,030 155 875 ------------------------------------------------------------------------------------------------------------------ Chemicals 827 456 371 815 409 406 ------------------------------------------------------------------------------------------------------------------ Corporate and Other 245 123 122 201 90 111 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ Total PP&E 15,062 5,468 9,594 13,127 4,924 8,203 ------------------------------------------------------------------------------------------------------------------
The above table includes capitalized costs of $5,211 million (2004--$3,945 million) relating to unproved properties and projects under construction or development. These costs are not being depreciated, depleted or amortized. DEPRECIATION, DEPLETION, AMORTIZATION AND IMPAIRMENT Included in our 2005 depreciation, depletion, amortization and impairment expense was $58 million relating to the writedown of a portion of our purchase price allocation to unproved properties purchased in the North Sea as a result of unsuccessful exploration activities. Our 2003 depreciation, depletion, amortization and impairment expense in the Consolidated Statement of Income includes an impairment charge of $269 million relating to certain Canadian oil and gas properties. The impairment resulted from negative reserve revisions and was largely attributable to Canadian heavy oil properties. The revisions resulted from changes in late field-life economic assumptions, changes in proved undeveloped reserves based on drilling results and geological mapping, and reassessments of estimated future production profiles. RESEARCH AND DEVELOPMENT We incurred $54 million (2004--$35 million) related to research and development activities. Costs of $44 million (2004--$26 million) were recorded in other expense on the Consolidated Statement of Income. The remaining costs have been deferred and are included in PP&E. 84 ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Development Costs Deferred, Beginning of Year 15 6 ------------------------------------------------------------------------------- Deferred in the Year 10 9 ------------------------------------------------------------------------------- Amortized in the Year - - ------------------------------------------------------------------------------- Development Costs Deferred, End of Year 25 15 ------------------------------------------------------------------------------- SUSPENDED WELL COSTS In the third quarter of 2005, we adopted staff position 19-1 (FSP 19-1) issued by the Financial Accounting Standards Board (FASB) on accounting for suspended well costs. FSP 19-1 amends FASB Statement No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, for companies using the successful efforts method of accounting, which required that capitalized exploratory well costs be expensed if related reserves could not be classified as proved within one year. FSP 19-1 provides that exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and sufficient progress is being made to assess the reserves and the economic and operating viability of the well. FSP 19-1 also requires certain disclosures with respect to capitalized exploratory well costs. The following table shows the changes in capitalized exploratory well costs during the years ended December 31, 2005 and 2004, and does not include amounts that were initially capitalized and subsequently expensed in the same period.
------------------------------------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year 116 89 ------------------------------------------------------------------------------------------------------------- Additions to Capitalized Exploratory Well Costs Pending the Determination of Proved Reserves 174 51 ------------------------------------------------------------------------------------------------------------- Capitalized Exploratory Well Costs Charged to Expense (27) (19) ------------------------------------------------------------------------------------------------------------- Transfers to Wells, Facilities and Equipment Based on Determination (3) - of Proved Reserves ------------------------------------------------------------------------------------------------------------- Effects of Foreign Exchange (8) (5) ------------------------------------------------------------------------------------------------------------- Balance at End of Year 252 116 -------------------------------------------------------------------------------------------------------------
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.
------------------------------------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------------------------------------- Capitalized for a Period of One Year or Less 165 53 ------------------------------------------------------------------------------------------------------------- Capitalized for a Period of Greater than One Year 87 63 ------------------------------------------------------------------------------------------------------------- Balance at End of Year 252 116 ------------------------------------------------------------------------------------------------------------- Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year Year 3 2 -------------------------------------------------------------------------------------------------------------
As at December 31, 2005, we have exploratory costs that have been capitalized for more than one year relating to our interest in an exploratory block, offshore Nigeria ($74 million), our interest in exploratory blocks in the Gulf of Mexico ($4 million) and coal bed methane exploratory activities in Canada ($9 million). Exploratory costs offshore Nigeria were first capitalized in 1998, and we have subsequently drilled a further seven successful wells on the block. The joint venture partners have finalized pre-development design studies and have submitted a field development plan for government approval. Drilling activity has resumed and an appraisal and exploration program is in progress. When final regulatory approvals have been received and the project has been sanctioned, we will book proved reserves. We have capitalized costs related to successful wells drilled in 2004 and 2005 in the Gulf of Mexico, and in Canada, we have capitalized exploratory costs relating to our coal bed methane projects. We are assessing all of these wells and projects, and we are working with our partners to prepare development plans. 85 7. DERIVATIVE INSTRUMENTS AND FINANCIAL RISK MANAGEMENT (a) CARRYING VALUE AND ESTIMATED FAIR VALUE OF DERIVATIVE AND FINANCIAL INSTRUMENTS The carrying values, fair values and unrecognized gains or losses on our outstanding derivatives and long-term financial assets and liabilities at December 31 are:
------------------------------------------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------------------------------------------- Carrying Fair Unrecognized Carrying Fair Unrecognized Value Value Gain Value Value Gain (Loss) (Loss) ------------------------------------------------------------------------------------------------------------------- Cdn$ millions ------------------------------------------------------------------------------------------------------------------- Commodity Price Risk ------------------------------------------------------------------------------------------------------------------- Non-Trading Activities ------------------------------------------------------------------------------------------------------------------- Crude Oil Put Options 4 4 - 200 200 - ------------------------------------------------------------------------------------------------------------------- Fixed Price Natural Gas ------------------------------------------------------------------------------------------------------------------- Contracts (175) (175) - - (98) (98) ------------------------------------------------------------------------------------------------------------------- Natural Gas Swaps 29 29 - - - - ------------------------------------------------------------------------------------------------------------------- Trading Activities ------------------------------------------------------------------------------------------------------------------- Crude Oil and Natural Gas 161 161 - 83 83 - ------------------------------------------------------------------------------------------------------------------- Future Sale of Gas Inventory - (35) (35) - 6 6 ------------------------------------------------------------------------------------------------------------------- Foreign Currency Risk ------------------------------------------------------------------------------------------------------------------- Non-Trading Activities 14 14 - 7 7 - ------------------------------------------------------------------------------------------------------------------- Trading Activities 8 8 - 10 10 - ------------------------------------------------------------------------------------------------------------------- Total Derivatives 41 6 (35) 300 208 (92) ------------------------------------------------------------------------------------------------------------------- Financial Assets and Liabilities ------------------------------------------------------------------------------------------------------------------- Long-Term Debt (3,687) (3,863) (176) (4,259) (4,503) (244) -------------------------------------------------------------------------------------------------------------------
The estimated fair value of all derivative instruments is based on quoted market prices and, if not available, on estimates from third-party brokers or dealers. The carrying value of cash and cash equivalents, restricted cash, amounts receivable and short-term obligations approximates their fair value because the instruments are near maturity. (b) COMMODITY PRICE RISK MANAGEMENT NON-TRADING ACTIVITIES We generally sell our crude oil and natural gas under short-term market-based contracts. CRUDE OIL PUT OPTIONS We purchased WTI crude oil put options to manage the commodity price risk exposure of a portion of our oil production in 2005 and 2006. These options established an annual average WTI floor price of US$43/bbl in 2005 and US$38/bbl in 2006 at a cost of $144 million. The WTI crude oil put options with respect to 2005 production were not used and have expired. The WTI crude oil put options with respect to 2006 production are stated at fair value and are included in deferred charges and other assets as they settle beyond 12 months of December 31, 2005. Any change in fair value is included in marketing and other on the Consolidated Statement of Income. ------------------------------------------------------------------------------ Notional Average Volumes Price (WTI) Fair Value WTI Crude Oil Put Options (bbls/d) Term (US$/bbl) (Cdn$ millions) ------------------------------------------------------------------------------ 30,000 2006 39 2 ------------------------------------------------------------------------------ 20,000 2006 38 1 ------------------------------------------------------------------------------ 10,000 2006 36 1 ------------------------------------------------------------------------------ 4 ------------------------------------------------------------------------------ 86 FIXED PRICE NATURAL GAS CONTRACTS AND NATURAL GAS SWAPS In July and August 2005, we sold certain Canadian oil and gas properties, and we retained fixed-price natural gas sales contracts that were previously associated with those properties (see Note 14). Since these contracts are no longer used in the normal course of our oil and gas operations, they have been marked-to-market and are included in the Consolidated Balance Sheet. Any change in fair value is included in marketing and other in the Consolidated Statement of Income. ------------------------------------------------------------------------------ Notional Average Fair Value Volumes Price (Cdn$ (Gj/d) Term ($/Gj) millions) ------------------------------------------------------------------------------ Fixed Price Natural Gas Contracts 22,034 2005-2006 2.28-3.72 (47) ------------------------------------------------------------------------------ 15,514 2007-2010 2.47-2.77 (128) ------------------------------------------------------------------------------ (175) ------------------------------------------------------------------------------ Following the sale of the Canadian oil and gas properties, we entered into natural gas swaps to economically hedge our exposure to the fixed-price natural gas contracts. Any change in fair value is included in marketing and other in the Consolidated Statement of Income. ------------------------------------------------------------------------------ Notional Average Fair Value Volumes Price (Cdn$ (Gj/d) Term ($/Gj) millions) ------------------------------------------------------------------------------ Natural Gas Swaps 22,034 2005-2006 9.02-11.81 1 ------------------------------------------------------------------------------ 15,514 2007-2010 7.45 28 ------------------------------------------------------------------------------ 29 ------------------------------------------------------------------------------ TRADING ACTIVITIES CRUDE OIL AND NATURAL GAS We enter into physical purchase and sales contracts as well as financial commodity contracts to enhance our price realizations and lock-in our margins. The physical and financial commodity contracts (derivative contracts) are stated at market value. The $161 million fair value of the commodity contracts at December 31, 2005 is included in the Consolidated Balance Sheet and any change in fair value is included in marketing and other in the Consolidated Statement of Income. FUTURE SALE OF GAS INVENTORY We have certain NYMEX futures contracts and swaps in place, which effectively lock-in our margins on the future sale of our natural gas inventory in storage. We have designated, in writing, some of these derivative contracts as cash flow hedges of the future sale of our storage inventory. As a result, gains and losses on these designated futures contracts, and swaps are recognized in net income when the inventory in storage is sold. The principal terms of these outstanding contracts and the unrecognized gains and losses at December 31, 2005 are:
------------------------------------------------------------------------------------------------------------ Hedged Average Unrecognized Volumes Price Loss (Cdn$ (mmcf) Month (US$/mcf) millions) ------------------------------------------------------------------------------------------------------------ Nymex Natural Gas Futures 9,100 January 2006 8.89 (27) ------------------------------------------------------------------------------------------------------------ 400 February 2006 10.96 - ------------------------------------------------------------------------------------------------------------ Nymex Natural Gas Fixed-Price and Basis Swaps 4,529 January 2006 9.15 (8) ------------------------------------------------------------------------------------------------------------ (35) ------------------------------------------------------------------------------------------------------------
87 (c) FOREIGN CURRENCY EXCHANGE RATE RISK MANAGEMENT
NON-TRADING ACTIVITIES ------------------------------------------------------------------------------------------------------------------------ Rate (for Fair Value Amount Term US$1.00) (Cdn$ millions) ------------------------------------------------------------------------------------------------------------------------ Foreign Currency Call Options--Buzzard (i) GBP207 million 2006 2.00 - ------------------------------------------------------------------------------------------------------------------------ US Dollar Call Options--Canexus (ii) US$11 million monthly 2006 0.813 6 ------------------------------------------------------------------------------------------------------------------------ Foreign Currency Swap (iii) US$37 million 2006 0.736 8 ------------------------------------------------------------------------------------------------------------------------ 14 -----------------------------------------------------------------------------------------------------------------------
(i) FOREIGN CURRENCY CALL OPTIONS--BUZZARD Our Buzzard development project in the North Sea creates foreign currency exposure as a portion of the capital costs are denominated in British pounds and Euros. To reduce our exposure to fluctuations in these currencies relative to the US dollar, we purchased foreign currency call options in early 2005, which effectively set a ceiling on most of our British pound and Euro spending exposure from March 2005 through to the end of 2006. Any change in fair value is included in marketing and other in the Consolidated Statement of Income. (ii) US DOLLAR CALL OPTIONS--CANEXUS The operations of Canexus are exposed to changes in the US-dollar exchange rate as a portion of its sales are denominated in US dollars. In connection with the initial public offering of Canexus, we purchased US-dollar call options to reduce this exposure to fluctuations in the Canadian-US dollar exchange rate. Canexus has the right to sell US$11 million monthly and purchase Canadian dollars at an exchange rate of US$0.813 until August 2006. Any change in fair value is included in marketing and other in the Consolidated Statement of Income. (iii) FOREIGN CURRENCY SWAP We occasionally use derivative instruments to effectively convert cash flows from Canadian to US dollars and vice versa. At December 31, 2005, we held a foreign currency derivative instrument that obligates us and the counterparty to exchange principal and interest amounts. In November 2006, we will pay US$37 million and receive Cdn$50 million (see Note 8). Any change in fair value is included in marketing and other in the Consolidated Statement of Income. OTHER The foreign exchange gains or losses related to our designated debt are included in the cumulative foreign currency translation adjustment in shareholders' equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at December 31 are as follows: ------------------------------------------------------------------------------- US$ millions 2005 2004 ------------------------------------------------------------------------------- Net Investment in Self-Sustaining Foreign Operations 4,357 3,973 ------------------------------------------------------------------------------- US-Dollar Debt 2,700 3,315 ------------------------------------------------------------------------------- We also have small exposures to currencies other than the US dollar. A portion of our capital spending on our Long Lake project is denominated in Euros and Japanese Yen. A portion of our United Kingdom operating expenses and capital spending is denominated in British pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. TRADING ACTIVITIES Our sales and purchases of crude oil and natural gas are generally transacted in or referenced to the US dollar, as are most of the financial commodity contracts used by our marketing group. We enter into forward contracts to sell US dollars. When combined with certain commodity sales contracts, either physical or financial, these forward contracts enable us to lock-in our margins on the future sale of crude oil and natural gas. The $8 million fair value of our US-dollar forward contracts and swaps at December 31, 2005 is included in the Consolidated Balance Sheet, and any change in fair value is included in marketing and other in the Consolidated Statement of Income. 88 (d) TOTAL CARRYING VALUE OF DERIVATIVE CONTRACTS RELATED TO TRADING ACTIVITIES Amounts related to derivative instruments held by our marketing operation are equal to fair value as we use mark-to-market accounting, and are as follows at December 31: ------------------------------------------------------------------------------- Cdn$ millions 2005 2004 ------------------------------------------------------------------------------- Accounts Receivable 382 177 ------------------------------------------------------------------------------- Deferred Charges and Other Assets (1) (Note 10) 232 91 ------------------------------------------------------------------------------- Total Derivative Contract Assets 614 268 ------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities 321 129 ------------------------------------------------------------------------------- Deferred Credits and Other Liabilities (1) (Note 11) 124 46 ------------------------------------------------------------------------------- Total Derivative Contract Liabilities 445 175 ------------------------------------------------------------------------------- Total Derivative Contract Net Assets (2) 169 93 ------------------------------------------------------------------------------- Note: (1) These derivative instruments settle beyond 12 months and are considered non-current. (2) Comprised of $161 million (2004--$83 million) related to commodity contracts and $8 million (2004--$10 million) related to US-dollar forward contracts and swaps. Our exchange-traded derivative contracts are subject to margin deposit requirements. We are required to advance cash to counterparties in order to satisfy these requirements. We did not have any margin deposit requirements at December 31, 2005 and 2004. (e) INTEREST RATE RISK MANAGEMENT We use fixed and floating rate debt to finance our operations. The floating rate debt exposes us to changes in interest payments as interest rates fluctuate. To manage this exposure, we maintain a combination of fixed and floating rate borrowings and facilities. At December 31, 2005, fixed-rate borrowings comprised 95% (2004--56%) of our long-term debt at an effective average rate of 6.3% (2004--6.6%). During the year we periodically drew on our floating rate unsecured syndicated term credit facilities. We had no interest rate swaps outstanding in 2005 or 2004. (f) CREDIT RISK MANAGEMENT A substantial portion of our accounts receivable are with counterparties in the energy industry and are subject to normal industry credit risk. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. We assess the financial strength of our counterparties, including those involved in marketing and other commodity arrangements, and we limit the total exposure to individual counterparties. As well, a number of our contracts contain provisions that allow us to demand the posting of collateral in the event downgrades to non-investment grade credit ratings occur. Credit risk, including credit concentrations, is routinely reported to our Risk Management Committee. We also use standard agreements that allow for the netting of exposures associated with a single counterparty. We believe this minimizes our overall credit risk. 89 8. LONG-TERM DEBT AND SHORT-TERM BORROWINGS ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Acquisition Credit Facilities (a) - 1,806 ------------------------------------------------------------------------------- Canexus LP Term Credit Facilities (US$147 million drawn) (b) 171 - ------------------------------------------------------------------------------- Term Credit Facilities (c) - 87 ------------------------------------------------------------------------------- Debentures, due 2006 (1) (d) 93 93 ------------------------------------------------------------------------------- Medium-Term Notes, due 2007 (e) 150 150 ------------------------------------------------------------------------------- Medium-Term Notes, due 2008 (f) 125 125 ------------------------------------------------------------------------------- Notes, due 2013 (US$500 million) (g) 583 602 ------------------------------------------------------------------------------- Notes, due 2015 (US$250 million) (h) 292 - ------------------------------------------------------------------------------- Notes, due 2028 (US$200 million) (i) 233 241 ------------------------------------------------------------------------------- Notes, due 2032 (US$500 million) (j) 583 602 ------------------------------------------------------------------------------- Notes, due 2035 (US$790 million) (k) 921 - ------------------------------------------------------------------------------- Subordinated Debentures, due 2043 (US$460 million) (l) 536 553 ------------------------------------------------------------------------------- Total 3,687 4,259 ------------------------------------------------------------------------------- Note: (1) Includes $50 million of principal that was effectively converted through a currency exchange contract to US$37 million. (a) ACQUISITION CREDIT FACILITIES During the year, we repaid all amounts outstanding under our acquisition credit facilities, which were used to fund a portion of the purchase price for the acquisition of EnCana UK in 2004. We replaced the US$500 million development facility associated with the acquisition credit facilities with the renewal of our term credit facilities. During 2005, the weighted average interest rate on the acquisition credit facilities was 3.9% (2004--3.2%). (b) CANEXUS LP TERM CREDIT FACILITIES Canexus LP has $350 million of committed, secured, revolving term credit facilities, which are available until 2009. At December 31, 2005, US$147 million ($171 million) was drawn on these facilities. Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at a floating rate. The term credit facilities are secured by a floating charge debenture over all of Canexus LP's assets and by certain guarantees, security interests and subordination agreements provided by certain affiliates of Canexus LP (which do not include Nexen). During 2005, the weighted- average interest rate on the Canexus LP term credit facilities was 4.8%. (c) TERM CREDIT FACILITIES We have committed, unsecured, term credit facilities of $2.4 billion, which are available until 2010. The lenders have the option to extend the term annually. Borrowings are available as Canadian bankers' acceptances, LIBOR-based loans, Canadian prime loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable monthly at a floating rate. During 2005, the weighted- average interest rate was 4.4% (2004--3.2%). At December 31, 2005, $250 million of these facilities were utilized to support letters of credit. (d) DEBENTURES, DUE 2006 During November 1996, we issued $100 million of unsecured 10-year redeemable debentures. Interest is payable semi-annually at a rate of 6.85% and the principal is to be repaid in November 2006. In December 1996, $50 million of this obligation was effectively converted through a currency exchange contract with a Canadian chartered bank to a US$37 million liability bearing interest at 6.75% for the term of the debentures. We may redeem part or all of the debentures at any time. The redemption price will be the greater of par and an amount that provides the same yield as a Government of Canada Bond having a term to maturity equal to the remaining term of the debentures plus 0.1%. Amounts due November 2006 have not been included in current liabilities as we expect to refinance this amount with our term credit facilities. 90 (e) MEDIUM-TERM NOTES, DUE 2007 During July 1997, we issued $150 million of notes. Interest is payable semi-annually at a rate of 6.45%, and the principal is to be repaid in July 2007. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a Government of Canada Bond having a term to maturity equal to the remaining term of the notes plus 0.125%. (f) MEDIUM-TERM NOTES, DUE 2008 During October 1997, we issued $125 million of notes. Interest is payable semi-annually at a rate of 6.3%, and the principal is to be repaid in June 2008. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a Government of Canada Bond having a term to maturity equal to the remaining term of the notes plus 0.125%. (g) NOTES, DUE 2013 During November 2003, we issued US$500 million of notes. Interest is payable semi-annually at a rate of 5.05%, and the principal is to be repaid in November 2013. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.2%. (h) NOTES, DUE 2015 During March 2005, we issued US$250 million of notes. Interest is payable semi-annually at a rate of 5.20%, and the principal is to be repaid in March 2015. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.15%. (i) NOTES, DUE 2028 During April 1998, we issued US$200 million of notes. Interest is payable semi-annually at a rate of 7.4%, and the principal is to be repaid in May 2028. We may redeem part or all of the notes any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.25%. (j) NOTES, DUE 2032 During March 2002, we issued US$500 million of notes. Interest is payable semi-annually at a rate of 7.875%, and the principal is to be repaid in March 2032. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.375%. (k) NOTES, DUE 2035 During March 2005, we issued US$790 million of notes. Interest is payable semi-annually at a rate of 5.875%, and the principal is to be repaid in March 2035. We may redeem part or all of the notes at any time. The redemption price will be the greater of par and an amount that provides the same yield as a US Treasury security having a term to maturity equal to the remaining term of the notes plus 0.2%. (l) SUBORDINATED DEBENTURES, DUE 2043 During November 2003, we issued US$460 million of unsecured subordinated debentures. Interest is payable quarterly in cash at a rate of 7.35%, and the principal is to be repaid in November 2043. We may redeem part or all of the debentures at any time on or after November 8, 2008. The redemption price is equal to the par value of the principal amount plus any accrued and unpaid interest to the redemption date. We may choose to redeem the principal amount with either cash or common shares. 91 (m) DEBT REPAYMENTS ------------------------------------------------------------------------------ 2006 93 ------------------------------------------------------------------------------ 2007 150 ------------------------------------------------------------------------------ 2008 125 ------------------------------------------------------------------------------ 2009 171 ------------------------------------------------------------------------------ 2010 - ------------------------------------------------------------------------------ Thereafter 3,148 ------------------------------------------------------------------------------ Total Debt Repayments 3,687 ------------------------------------------------------------------------------ (n) DEBT COVENANTS Some of our debt instruments contain covenants with respect to certain financial ratios and our ability to grant security. At December 31, 2005, we were in compliance with all covenants. (o) SHORT-TERM BORROWINGS Nexen has uncommitted, unsecured credit facilities of approximately $732 million. No amounts were drawn under these facilities at December 31, 2005 (2004--$100 million). We have utilized $468 million of these facilities to support letters of credit at December 31, 2005. Interest is payable at floating rates. During 2005, the weighted-average interest rate on our short-term borrowings was 3.6% (2004--2.9%). (p) INTEREST EXPENSE ------------------------------------------------------------------------------ 2005 2004 2003 ------------------------------------------------------------------------------ Long-Term Debt 260 182 204 ------------------------------------------------------------------------------ Other 15 12 8 ------------------------------------------------------------------------------ Total 275 194 212 ------------------------------------------------------------------------------ Less: Capitalized (178) (51) (43) ------------------------------------------------------------------------------ Total Interest Expense 97 143 169 ------------------------------------------------------------------------------ Capitalized interest relates to and is included as part of the cost of oil and gas and Syncrude properties. The capitalization rates are based on our weighted-average cost of borrowings. 9. ASSET RETIREMENT OBLIGATIONS Changes in carrying amounts of the asset retirement obligations associated with our PP&E are as follows: ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Balance at Beginning of Year 468 323 ------------------------------------------------------------------------------- Obligations Assumed with Development Activities 72 12 ------------------------------------------------------------------------------- Obligations Assumed with Business Acquisition - 134 ------------------------------------------------------------------------------- Obligations Discharged with Disposed Properties (37) (4) ------------------------------------------------------------------------------- Expenditures Made on Asset Retirements (34) (31) ------------------------------------------------------------------------------- Accretion 26 17 ------------------------------------------------------------------------------- Revisions to Estimates 138 24 ------------------------------------------------------------------------------- Effects of Foreign Exchange (22) (7) ------------------------------------------------------------------------------- Balance at End of Year (1), (2) 611 468 ------------------------------------------------------------------------------- Notes: (1) Obligations due within 12 months of $21 million (2004--$47 million) have been included in accounts payable and accrued liabilities. Obligations related to discontinued operations of $22 million have been included with liabilities of discontinued operations at December 31, 2004. (2) Obligations relating to our oil and gas activities amount to $564 million (2004--$422 million) and obligations relating to our chemicals business amount to $47 million (2004--$46 million). Our total estimated undiscounted asset retirement obligations amount to $1,471 million. We have discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted risk-free rate of 5.7%. Approximately $88 million included in our asset retirement obligations will be settled over the next five years. The remaining obligations settle beyond five years and will be funded by future cash flows from our operations. 92 In connection with the sale of our chemicals business to Canexus LP, we have contributed $14 million to a remediation fund to be used for asset retirement obligations associated with the assets sold. This is included on our balance sheet as part of deferred charges and other assets. We own interests in assets for which the fair value of the asset retirement obligations cannot be reasonably determined because the assets currently have an indeterminate life and we cannot determine when remediation activities would take place. These assets include our interest in Syncrude's upgrader and sulphur pile. The estimated future recoverable reserves at Syncrude are significant and given the long life of this asset, we are unable to determine when asset retirement activities would take place. Furthermore, the Syncrude plant can continue to run indefinitely with ongoing maintenance activities. The retirement obligations for these assets will be recorded in the first year in which the lives of the assets are determinable. 10. DEFERRED CHARGES AND OTHER ASSETS ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Long-Term Marketing Derivative Contracts (Note 7d) 232 91 ------------------------------------------------------------------------------- Deferred Financing Costs 63 67 ------------------------------------------------------------------------------- Asset Retirement Remediation Fund (Note 9) 14 - ------------------------------------------------------------------------------- Crude Oil Put Options (Note 7) 4 200 ------------------------------------------------------------------------------- Defined Benefit Pension Plan Asset (Note 16) - 13 ------------------------------------------------------------------------------- Other 85 58 ------------------------------------------------------------------------------- Total 398 429 ------------------------------------------------------------------------------- 11. DEFERRED CREDITS AND OTHER LIABILITIES ------------------------------------------------------------------------------- 2005 2004 ------------------------------------------------------------------------------- Fixed-Price Natural Gas Contracts (Note 7b) 128 - ------------------------------------------------------------------------------- Long-Term Marketing Derivative Contracts (Note 7d) 124 46 ------------------------------------------------------------------------------- Deferred Transportation 87 33 ------------------------------------------------------------------------------- Stock-Based Compensation Liability 53 - ------------------------------------------------------------------------------- Defined Benefit Pension Obligation (Note 16) 39 32 ------------------------------------------------------------------------------- Other 48 31 ------------------------------------------------------------------------------- Total 479 142 ------------------------------------------------------------------------------- 12. SHAREHOLDERS' EQUITY (a) AUTHORIZED CAPITAL Authorized share capital consists of an unlimited number of common shares of no par value, and an unlimited number of Class A preferred shares of no par value, issuable in series. Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 27, 2005. All common shares, per common share amounts, stock options and stock appreciation rights together with their related weighted-average exercise prices, have been restated to retroactively reflect the share split. 93 (b) ISSUED COMMON SHARES AND DIVIDENDS ------------------------------------------------------------------------------- (thousands of shares) 2005 2004 2003 ------------------------------------------------------------------------------- Beginning of Year 258,399 251,212 245,932 ------------------------------------------------------------------------------- Issue of Common Shares for Cash ------------------------------------------------------------------------------- Exercise of Stock Options 1,823 5,902 3,928 ------------------------------------------------------------------------------- Dividend Reinvestment Plan 605 895 952 ------------------------------------------------------------------------------- Employee Flow-through Shares 314 390 400 ------------------------------------------------------------------------------- End of Year 261,141 258,399 251,212 ------------------------------------------------------------------------------- Dividends Declared per Common Share ($/share) 0.20 0.20 0.1625 ------------------------------------------------------------------------------- Cash Consideration (Cdn$ millions) ------------------------------------------------------------------------------- Exercise of Stock Options 29 93 50 ------------------------------------------------------------------------------- Dividend Reinvestment Plan 20 21 15 ------------------------------------------------------------------------------- Employee Flow-through Shares 9 10 8 ------------------------------------------------------------------------------- 58 124 73 ------------------------------------------------------------------------------- At December 31, 2005, there were 774,915 common shares (2004--1,379,874; 2003--2,274,610) reserved for issuance under the Dividend Reinvestment Plan. (c) STOCK OPTIONS In May 2004, our shareholders approved the modification of our stock option plan to a tandem option plan by including a cash feature. The tandem options give the holders a right to either purchase common shares at the exercise price or to receive cash payments equal to the excess of the market value of the common shares over the exercise price. Similar to our stock appreciation rights, we use the intrinsic-value method to recognize compensation expense associated with our tandem options. Obligations are accrued on a graded vesting basis and represent the difference between the market value of our common shares and the exercise price of the options. The obligations are revalued each reporting period based on the change in the market value of our common shares and the number of graded vested options outstanding. Upon modification of the stock option plan, we were required to recognize an obligation for our tandem options. This obligation represented the difference between the market value of our common shares and the weighted-average exercise price of the options. As a result, we recognized an obligation of $85 million for the graded vested portion of the options outstanding on June 30, 2004. In the second quarter of 2004, a one-time, non-cash charge of $82 million was included in general and administrative expense, net of $3 million previously expensed in respect of our original stock options. Following the introduction of the American Job Creation Act of 2004 in the US, stock options awarded to our US employees between December 1, 2004 and December 1, 2005 did not include a tandem option cash feature. We use the fair-value method to recognize compensation expense associated with these options. The expense is recognized over the vesting period of the options with a corresponding increase to contributed surplus. This resulted in compensation expense in 2005 of $2 million (2004--$0.1 million) which was included in general and administrative expense. In 2005, US tax regulations were modified. As a result, tandem options have been issued to our US employees after December 1, 2005. These options are expensed using the intrinsic-method described above. 94 We have granted options to purchase common shares to directors, officers and employees. Each option permits the holder to purchase one Nexen common share at the stated exercise price. Options granted prior to February 2001 vest over four years and are exercisable on a cumulative basis over 10 years. Options granted after February 2001 vest over three years and are exercisable on a cumulative basis over five years. At the time of grant, the exercise price equals the market price. The following options have been granted:
---------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ---------------------------------------------------------------------------------------------------------------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Options Price Options Price Options Price ---------------------------------------------------------------------------------------------------------------------------- (thousands) ($/options) (thousands) ($/options) (thousands) ($/options) ---------------------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year 16,276 20 18,406 17 18,952 15 ---------------------------------------------------------------------------------------------------------------------------- Granted 3,392 55 4,224 25 3,753 22 ---------------------------------------------------------------------------------------------------------------------------- Exercised for Stock (1,823) 16 (5,902) 15 (3,927) 14 ---------------------------------------------------------------------------------------------------------------------------- Surrendered for Cash (2,089) 17 (289) 17 - - ---------------------------------------------------------------------------------------------------------------------------- Forfeited (441) 22 (163) 17 (372) 16 ---------------------------------------------------------------------------------------------------------------------------- Balance at End of Year 15,315 28 16,276 20 18,406 17 ---------------------------------------------------------------------------------------------------------------------------- Options Exercisable at End of Year 8,131 19 8,455 17 10,133 15 ---------------------------------------------------------------------------------------------------------------------------- Common Shares Reserved for Issuance Under the Stock Option Plan 17,290 19,172 19,576 ---------------------------------------------------------------------------------------------------------------------------
The range of exercise prices of options outstanding and exercisable at December 31, 2005 is as follows:
------------------------------------------------------------------------------------------------------------- Outstanding Options Exercisable Options ------------------------------------------------------------------------------------------------------------- Weighted Weighted Average Average Weighted Average Number of Exercise Years to Number of Exercise Options Price Expiry Options Price ------------------------------------------------------------------------------------------------------------- (thousands) ($/options) (years) (thousands) ($/options) ------------------------------------------------------------------------------------------------------------- $5.00 to $9.99 196 9 3 196 9 ------------------------------------------------------------------------------------------------------------- $10.00 to $14.99 1,198 13 3 1,198 13 ------------------------------------------------------------------------------------------------------------- $15.00 to $19.99 4,266 18 3 3,992 17 ------------------------------------------------------------------------------------------------------------- $20.00 to $24.99 3,311 23 3 1,774 22 ------------------------------------------------------------------------------------------------------------- $25.00 to $29.99 2,974 25 4 971 25 ------------------------------------------------------------------------------------------------------------- $30.00 to $34.99 38 31 4 - - ------------------------------------------------------------------------------------------------------------- $35.00 to $39.99 - - - - - ------------------------------------------------------------------------------------------------------------- $40.00 to $44.99 2 40 5 - - ------------------------------------------------------------------------------------------------------------- $45.00 to $49.99 14 47 5 - - ------------------------------------------------------------------------------------------------------------- $50.00 to $54.99 2,669 55 5 - - ------------------------------------------------------------------------------------------------------------- $55.00 to $59.99 647 55 5 - - ------------------------------------------------------------------------------------------------------------- Total Options 15,315 8,131 -------------------------------------------------------------------------------------------------------------
In previous periods, we estimated the fair value of stock options issued using the Generalized Black-Scholes option pricing model under the following assumptions: ------------------------------------------------------------------------------ 2003 ------------------------------------------------------------------------------ Weighted-Average Fair Value ($/option) 10.10 ------------------------------------------------------------------------------ Risk-Free Interest Rate (%) 3.6 ------------------------------------------------------------------------------ Estimated Hold Period Prior to Exercise (years) 3 ------------------------------------------------------------------------------ Volatility in the Price of Nexen's Common Shares (%) 30 ------------------------------------------------------------------------------ Dividends per Common Share ($/share) 0.40 ------------------------------------------------------------------------------ 95 The following shows pro forma net income and earnings per common share had we applied the fair-value method to account for all stock options outstanding that were granted up to December 31, 2002. Stock options granted after that date have been expensed as general and administrative costs. ------------------------------------------------------------------------------- 2003 ------------------------------------------------------------------------------- Fair Value of Stock Options Granted 25 ------------------------------------------------------------------------------- Less: Fair Value of Stock Options Expensed (1) ------------------------------------------------------------------------------- 24 ------------------------------------------------------------------------------- Net Income Attributable to Common Shareholders ------------------------------------------------------------------------------- As Reported 578 ------------------------------------------------------------------------------- Pro Forma 554 ------------------------------------------------------------------------------- Earnings Per Common Share ($/share) ------------------------------------------------------------------------------- Basic as Reported 2.33 ------------------------------------------------------------------------------- Pro Forma 2.24 ------------------------------------------------------------------------------- Diluted as Reported 2.31 ------------------------------------------------------------------------------- Pro Forma 2.22 ------------------------------------------------------------------------------- (d) STOCK APPRECIATION RIGHTS Under our stock appreciation rights (StARs) plan established in 2001, employees are entitled to cash payments equal to the excess of the market price of the common shares over the exercise price of the right. The vesting period and other terms of the plan are similar to the stock option plan. The total rights granted and outstanding at any time cannot exceed 10% of Nexen's total outstanding common shares. At the time of grant, the exercise price equals the market price. The following stock appreciation rights have been granted:
------------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise StARs Price StARs Price StARs Price ------------------------------------------------------------------------------------------------------------------------------- (thousands) ($/right) (thousands) ($/right) (thousands) ($/right) ------------------------------------------------------------------------------------------------------------------------------- Balance at Beginning of Year 6,436 22 4,809 18 3,625 17 ------------------------------------------------------------------------------------------------------------------------------- Granted 1,443 55 2,609 25 2,033 22 ------------------------------------------------------------------------------------------------------------------------------- Exercised for Cash (1,455) 19 (867) 16 (725) 16 ------------------------------------------------------------------------------------------------------------------------------- Forfeited (460) 23 (115) 18 (124) 16 ------------------------------------------------------------------------------------------------------------------------------- Balance at End of Year 5,964 30 6,436 22 4,809 18 ------------------------------------------------------------------------------------------------------------------------------- Rights Exercisable at End of Year 2,426 21 2,021 17 990 17 -------------------------------------------------------------------------------------------------------------------------------
96 The range of exercise prices of StARs outstanding and exercisable at December 31, 2005 is as follows:
--------------------------------------------------------------------------------------------------------------- Outstanding StARs Exercisable StARs --------------------------------------------------------------------------------------------------------------- Weighted Weighted Weighted Average Average Average Number of Exercise Years to Number of Exercise StARs Price Expiry StARs Price --------------------------------------------------------------------------------------------------------------- (thousands) ($/right) (years) (thousands) ($/right) --------------------------------------------------------------------------------------------------------------- $15.00 to 1,028 16 2 1,024 16 $19.99 --------------------------------------------------------------------------------------------------------------- $20.00 to $24.99 1,308 22 3 737 22 --------------------------------------------------------------------------------------------------------------- $25.00 to $29.99 2,193 25 4 665 25 --------------------------------------------------------------------------------------------------------------- $30.00 to $34.99 18 33 4 - - --------------------------------------------------------------------------------------------------------------- $35.00 to $39.99 15 37 5 - - --------------------------------------------------------------------------------------------------------------- $40.00 to $44.99 9 41 5 - - --------------------------------------------------------------------------------------------------------------- $45.00 to $49.99 39 48 5 - - --------------------------------------------------------------------------------------------------------------- $50.00 to $54.99 1,353 55 5 - - --------------------------------------------------------------------------------------------------------------- $55.00 to $59.99 1 55 5 - - --------------------------------------------------------------------------------------------------------------- Total StARs 5,964 2,426 ---------------------------------------------------------------------------------------------------------------
13. EARNINGS PER COMMON SHARE Our shareholders approved a split of our issued and outstanding common shares on a two-for-one basis at our annual and special meeting on April 27, 2005. All common share and per common share amounts have been restated to retroactively reflect this share split. We calculate basic earnings per common share from continuing operations using net income from continuing operations divided by the weighted-average number of common shares outstanding. We calculate basic earnings per common share using net income and the weighted-average number of common shares outstanding. We calculate diluted earnings per common share from continuing operations and diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
------------------------------------------------------------------------------------------------- (millions of shares) 2005 2004 2003 ------------------------------------------------------------------------------------------------- Weighted-Average Number of Common Shares Outstanding 260.4 257.3 247.5 ------------------------------------------------------------------------------------------------- Shares Issuable Pursuant to Stock Options 13.4 13.1 12.6 ------------------------------------------------------------------------------------------------- Shares to be Purchased from Proceeds of Stock Options (7.4) (9.8) (10.2) ------------------------------------------------------------------------------------------------- Weighted-Average Number of Diluted Common Shares Outstanding 266.4 260.6 249.9 -------------------------------------------------------------------------------------------------
In calculating the weighted-average number of diluted common shares outstanding for the year ended December 31, 2005, we excluded 280,708 options (2004--348,200; 2003--5,634,046), because their exercise price was greater than the annual average common share market price in those periods. During the last three years, outstanding stock options were the only potential dilutive instruments. 14. DISCONTINUED OPERATIONS In the third quarter of 2005, we sold certain Canadian conventional oil and gas properties in southeast Saskatchewan, northwest Saskatchewan, northeast British Columbia and the Alberta foothills. The results of operations of these properties have been presented as discontinued operations. The sales closed in the third quarter of 2005 with net proceeds of $900 million after closing adjustments, and we realized gains of $225 million. These gains are net of losses attributable to pipeline contracts and fixed price gas sales contracts associated with these properties that we have retained, but no longer use in connection with our oil and gas business. During the fourth quarter of 2004, we concluded production from our Buffalo field, offshore Australia. The results of our operations in Australia have been presented as discontinued operations, as we have no plans to continue operations in the country. Remediation and abandonment activities have been completed, and no gain or loss was recognized. During the third quarter of 2003, we sold certain non-core conventional light oil properties in southeast Saskatchewan. Net proceeds were $268 million, and there was no gain or loss on the sale. 97 The results of operations from these properties in Australia and Canada are detailed below and shown as discontinued operations in our Consolidated Statement of Income.
------------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------------- Canada Canada Australia Total Canada Australia Total ------------------------------------------------------------------------------------------------------------------------- Revenues and Other Income ------------------------------------------------------------------------------------------------------------------------- Net Sales 154 232 75 307 278 64 342 ------------------------------------------------------------------------------------------------------------------------- Marketing and Other - 1 - 1 - - - ------------------------------------------------------------------------------------------------------------------------- Gain on Disposition of Assets 225 - - - - - - ------------------------------------------------------------------------------------------------------------------------- 379 233 75 308 278 64 342 ------------------------------------------------------------------------------------------------------------------------- Expenses ------------------------------------------------------------------------------------------------------------------------- Operating 27 40 53 93 49 30 79 ------------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and 28 70 9 79 101 22 123 Impairment ------------------------------------------------------------------------------------------------------------------------- General and Administrative - - - - 5 - 5 ------------------------------------------------------------------------------------------------------------------------- Exploration Expense 1 3 - 3 7 1 8 ------------------------------------------------------------------------------------------------------------------------- Income before Income Taxes 323 120 13 133 116 11 127 ------------------------------------------------------------------------------------------------------------------------- Current Income Taxes - - - - - (4) (4) ------------------------------------------------------------------------------------------------------------------------- Future Income Taxes (129) 50 - 50 58 2 60 ------------------------------------------------------------------------------------------------------------------------- Net Income 452 70 13 83 58 13 71 ------------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------------- Earnings per Common Share ($/share) ------------------------------------------------------------------------------------------------------------------------- Basic (Note 13) 1.74 0.27 0.05 0.32 0.23 0.05 0.28 ------------------------------------------------------------------------------------------------------------------------- Diluted (Note 13) 1.70 0.27 0.05 0.32 0.23 0.05 0.28 -------------------------------------------------------------------------------------------------------------------------
Assets and liabilities on the Consolidated Balance Sheet as at December 31, 2004, include the following amounts for discontinued operations:
---------------------------------------------------------------------------------------------------------------------- Canada Australia Total ---------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents - 1 1 ---------------------------------------------------------------------------------------------------------------------- Accounts Receivable 28 8 36 ---------------------------------------------------------------------------------------------------------------------- Other Current Assets - 1 1 ---------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, Net 440 - 440 ---------------------------------------------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities 14 25 39 ---------------------------------------------------------------------------------------------------------------------- Asset Retirement Obligations 22 - 22 ---------------------------------------------------------------------------------------------------------------------- Future Income Tax Liabilities 108 - 108 ----------------------------------------------------------------------------------------------------------------------
There were no assets and liabilities related to discontinued operations as at December 31, 2005. 15. COMMITMENTS, CONTINGENCIES AND GUARANTEES
---------------------------------------------------------------------------------------------------------------------- 2006 2007 2008 2009 2010 Thereafter ---------------------------------------------------------------------------------------------------------------------- Operating Leases 33 33 30 29 26 121 ---------------------------------------------------------------------------------------------------------------------- Transportation and Storage Commitments 440 133 97 57 45 116 ---------------------------------------------------------------------------------------------------------------------- 473 166 127 86 71 237 ----------------------------------------------------------------------------------------------------------------------
We have a number of lawsuits and claims pending including income tax reassessments (see Note 18), for which we currently cannot determine the ultimate result. We record costs as they are incurred or become determinable. We believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations. During 2005, total rental expense was $47 million (2004--$45 million; 2003--$49 million). From time to time, we enter into certain types of contracts that require us to indemnify parties against possible third-party claims, particularly when these contracts relate to divestiture transactions. On occasion, we may provide routine indemnifications. The terms of such obligations vary, and generally, a maximum is not explicitly stated. Because the obligations in these agreements are often not explicitly stated, the overall maximum amount of the obligations cannot be reasonably estimated. Historically, we have not been obligated to make significant payments for these obligations. Our Risk Management Committee actively monitors our exposure to the above risks and obtains insurance coverage to satisfy potential or future claims as necessary. We believe that 98 payments, if any, related to such matters, would not have a material adverse effect on our liquidity, financial condition or results of operations. 16. PENSION AND OTHER POST-RETIREMENT BENEFITS Nexen has contributory and non-contributory defined benefit and defined contribution pension plans, which together cover substantially all employees. Syncrude has a defined benefit plan for its employees, and we disclose only our share of this plan. Under these defined benefit plans, we provide benefits to retirees based on their length of service and final average earnings. Benefits paid out of Nexen's defined benefit plan are indexed to 75% of the annual rate of inflation less 1%, to a maximum increase of 5%. On the establishment of Canexus during 2005, the portion of the projected benefit obligation and fair value of plan assets relating to Canexus employees was transferred to Canexus from Nexen, subject to regulatory approval. Canexus' pension and other post retirement benefit amounts have been disclosed separately for 2005. 99 (a) DEFINED BENEFIT PENSION PLANS The cost of pension benefits earned by employees is determined using the projected-benefit method prorated on employment services and is expensed as services are rendered. We fund these plans according to federal and provincial government regulations by contributing to trust funds administered by an independent trustee. These funds are invested primarily in equities and bonds.
--------------------------------------------------------------------------------------------------------------------- 2005 2004 --------------------------------------------------------------------------------------------------------------------- Nexen Canexus Syncrude Nexen Syncrude --------------------------------------------------------------------------------------------------------------------- Change in Projected Benefit Obligation (PBO) --------------------------------------------------------------------------------------------------------------------- Beginning of Year 217 - 91 192 79 --------------------------------------------------------------------------------------------------------------------- Service Cost 15 1 4 8 3 --------------------------------------------------------------------------------------------------------------------- Interest Cost 12 1 5 12 5 --------------------------------------------------------------------------------------------------------------------- Plan Participants' Contributions 3 - 1 2 - --------------------------------------------------------------------------------------------------------------------- Actuarial Loss/(Gain) 33 (2) 11 10 7 --------------------------------------------------------------------------------------------------------------------- Benefits Paid (8) - (3) (7) (3) --------------------------------------------------------------------------------------------------------------------- Transfer to Canexus (49) 49 - - - --------------------------------------------------------------------------------------------------------------------- End of Year (1) 223 49 109 217 91 --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Change in Fair Value of Plan Assets --------------------------------------------------------------------------------------------------------------------- Beginning of Year 171 - 50 154 44 --------------------------------------------------------------------------------------------------------------------- Actual Return on Plan Assets 18 - 6 16 5 --------------------------------------------------------------------------------------------------------------------- Employer's Contribution 2 - 4 6 4 --------------------------------------------------------------------------------------------------------------------- Plan Participants' Contributions 3 - 1 2 - --------------------------------------------------------------------------------------------------------------------- Benefits Paid (8) - (3) (7) (3) --------------------------------------------------------------------------------------------------------------------- Transfer to Canexus (40) 40 - - - --------------------------------------------------------------------------------------------------------------------- End of Year 146 40 58 171 50 --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Reconciliation of Funded Status --------------------------------------------------------------------------------------------------------------------- Funded Status (2) (77) (9) (51) (46) (41) --------------------------------------------------------------------------------------------------------------------- Unamortized Transitional Obligation 1 - - 1 - --------------------------------------------------------------------------------------------------------------------- Unamortized Prior Service Costs 3 - - 4 - --------------------------------------------------------------------------------------------------------------------- Unamortized Net Actuarial Loss 44 9 38 30 30 --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Pension Liability (29) - (13) (11) (11) --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Pension Liability Recognized --------------------------------------------------------------------------------------------------------------------- Deferred Charges and Other Assets (Note 10) - - - 13 - --------------------------------------------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities (1) - (2) (1) (2) --------------------------------------------------------------------------------------------------------------------- Other Deferred Credits and Liabilities (Note 11) (28) - (11) (23) (9) --------------------------------------------------------------------------------------------------------------------- Pension Liability (29) - (13) (11) (11) --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Assumptions (%) --------------------------------------------------------------------------------------------------------------------- Accrued Benefit Obligation at December 31 --------------------------------------------------------------------------------------------------------------------- Discount Rate 5.25 5.25 5.00 6.00 5.75 --------------------------------------------------------------------------------------------------------------------- Long-Term Rate of Employee Compensation Increase 4.00 4.00 4.00 4.00 4.00 --------------------------------------------------------------------------------------------------------------------- Benefit Cost for Year Ended December 31 (3) --------------------------------------------------------------------------------------------------------------------- Discount Rate 5.00 5.00 5.00 6.25 6.00 --------------------------------------------------------------------------------------------------------------------- Long-Term Rate of Employee Compensation Increase 4.00 4.00 4.00 4.00 4.00 --------------------------------------------------------------------------------------------------------------------- Long-Term Annual Rate of Return on Plan Assets (4) 7.00 6.50 8.50 7.00 8.50 ---------------------------------------------------------------------------------------------------------------------
Notes: (1) The accumulated benefit obligations (the projected benefit obligation excluding future salary increases) of the Nexen and Canexus plans were $161 million and $36 million at December 31, 2005, respectively. Nexen's supplemental pension plan's accumulated benefit obligation was $29 million at December 31, 2005, and Canexus' was nil. Nexen's share of Syncrude's employee pension plan's accumulated benefit obligation was $82 million at December 31, 2005. (2) Includes unfunded obligations for supplemental benefits to the extent that the benefit is limited by statutory guidelines. At December 31, 2005, the PBO for Nexen's supplemental benefits was $43 million (2004--$34 million) and $1 million for Canexus (2004--nil). (3) The assumptions have been used to calculate the recognized expense for Nexen and Canexus. There were no changes to the assumptions between the measurement date and December 31, 2005. Syncrude's measurement date was December 31, 2005. (4) The long-term annual rate of return on plan assets assumption is based on a mix of historical market returns for debt and equity securities. 100
NET PENSION EXPENSE RECOGNIZED UNDER OUR DEFINED BENEFIT PENSION PLANS ---------------------------------------------------------------------------------------------------------- 2005 2004 2003 ---------------------------------------------------------------------------------------------------------- Nexen ---------------------------------------------------------------------------------------------------------- Cost of Benefits Earned by Employees 15 8 7 ---------------------------------------------------------------------------------------------------------- Interest Cost on Benefits Earned 12 12 11 ---------------------------------------------------------------------------------------------------------- Actual Return on Plan Assets (18) (16) (15) ---------------------------------------------------------------------------------------------------------- Actuarial Losses 33 10 14 ---------------------------------------------------------------------------------------------------------- Pension Expense Before Adjustments for the Long-Term Nature of ---------------------------------------------------------------------------------------------------------- Employee Future Benefit Costs 42 14 17 ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Expected Return 8 5 7 ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Actuarial Losses (32) (10) (15) ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Past Service Costs - 1 1 ---------------------------------------------------------------------------------------------------------- Net Pension Expense 18 10 10 ---------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------- Canexus ---------------------------------------------------------------------------------------------------------- Cost of Benefits Earned by Employees 1 - - ---------------------------------------------------------------------------------------------------------- Interest Cost on Benefits Earned 1 - - ---------------------------------------------------------------------------------------------------------- Actual Return on Plan Assets - - - ---------------------------------------------------------------------------------------------------------- Actuarial Gains (2) - - ---------------------------------------------------------------------------------------------------------- Pension Expense Before Adjustments for the Long-Term Nature of ---------------------------------------------------------------------------------------------------------- Employee Future Benefit Costs - - - ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Expected Return (1) - - ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Actuarial Gains 2 - - ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Past Service Costs - - - ---------------------------------------------------------------------------------------------------------- Net Pension Expense 1 - - ---------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------- Syncrude ---------------------------------------------------------------------------------------------------------- Cost of Benefits Earned by Employees 4 3 3 ---------------------------------------------------------------------------------------------------------- Interest Cost on Benefits Earned 5 5 4 ---------------------------------------------------------------------------------------------------------- Actual Return on Plan Assets (6) (5) (7) ---------------------------------------------------------------------------------------------------------- Actuarial Losses 11 7 6 ---------------------------------------------------------------------------------------------------------- Pension Expense Before Adjustments for the Long-Term Nature of ---------------------------------------------------------------------------------------------------------- Employee Future Benefit Costs 14 10 6 ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Expected Return 2 1 4 ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Actuarial Losses (8) (6) (5) ---------------------------------------------------------------------------------------------------------- Difference Between Actual and Recognized Past Service Costs - - - ---------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------- Net Pension Expense 8 5 5 ---------------------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------------------- Total Net Pension Expense 27 15 15 ----------------------------------------------------------------------------------------------------------
(b) PLAN ASSET ALLOCATION AT DECEMBER 31 Our investment goal for the assets in our defined benefit pension plans is to preserve capital and earn a long-term rate of return on assets, net of all management expenses, in excess of the inflation rate. Investment funds are managed by external fund managers based on policies approved by the Board of Directors and Pension Committees of Nexen and Canexus. Nexen's and Canexus' investment strategy is to diversify plan assets between debt and equity securities of Canadian and non-Canadian corporations that are traded on recognized stock exchanges. Allowable and prohibited investment types are also prescribed in Nexen's investment policies. 101 Syncrude's pension plan is governed and administered separately from ours. Syncrude's investment assets are subject to a similar investment goal, policy and strategy.
----------------------------------------------------------------------------------------------------- Expected (%) 2006 2005 2004 ----------------------------------------------------------------------------------------------------- Nexen ----------------------------------------------------------------------------------------------------- Equity Securities 60 60 60 ----------------------------------------------------------------------------------------------------- Debt Securities 40 40 40 ----------------------------------------------------------------------------------------------------- Real Estate - - - ----------------------------------------------------------------------------------------------------- Other - - - ----------------------------------------------------------------------------------------------------- Total 100 100 100 ----------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------- Canexus ----------------------------------------------------------------------------------------------------- Equity Securities 60 60 - ----------------------------------------------------------------------------------------------------- Debt Securities 40 40 - ----------------------------------------------------------------------------------------------------- Real Estate - - - ----------------------------------------------------------------------------------------------------- Other - - - ----------------------------------------------------------------------------------------------------- Total 100 100 - ----------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------- Syncrude ----------------------------------------------------------------------------------------------------- Equity Securities 70 70 70 ----------------------------------------------------------------------------------------------------- Debt Securities 30 30 30 ----------------------------------------------------------------------------------------------------- Real Estate - - - ----------------------------------------------------------------------------------------------------- Other - - - ----------------------------------------------------------------------------------------------------- Total 100 100 100 -----------------------------------------------------------------------------------------------------
(c) DEFINED CONTRIBUTION PENSION PLANS Under these plans, pension benefits are based on plan contributions. During 2005, Canadian pension expense for these plans was $4 million (2004--$4 million; 2003--$4 million). During 2005, US pension expense for these plans was $4 million (2004--$3 million; 2003--$3 million). (d) POST-RETIREMENT BENEFITS Nexen provides certain post-retirement benefits, including group life and supplemental health insurance, to eligible employees and their dependents. These costs are fully accrued as compensation in the period employees work; however, these future obligations are not funded. The present value of Nexen employees' future post retirement benefits in 2005 was $4 million (2004--$5 million) and $2 million for Canexus (2004--nil). Nexen's share of post-retirement and post-employment benefits related to Syncrude in 2005 was $5 million (2004--$7 million). (e) EMPLOYER FUNDING CONTRIBUTIONS AND BENEFIT PAYMENTS Canadian regulators have prescribed funding requirements for our defined benefit plans. Our funding contributions over the last three years have met these requirements and also included additional discretionary contributions permitted by law. For our defined contribution plans, we always match the employee contribution, and no further obligation exists. Our funding contributions for the defined benefit plans are:
------------------------------------------------------------------------------------------------------- Expected 2006 2005 2004 ------------------------------------------------------------------------------------------------------- Defined Benefit Contributions ------------------------------------------------------------------------------------------------------- Nexen 18 2 6 ------------------------------------------------------------------------------------------------------- Canexus 2 - - ------------------------------------------------------------------------------------------------------- Syncrude 5 4 4 ------------------------------------------------------------------------------------------------------- Total Funding Contributions 25 6 10 -------------------------------------------------------------------------------------------------------
Our most recent funding valuation was prepared as of August 17, 2005. Our next funding valuation is required by June 30, 2008. Canexus' most recent funding valuation was prepared as of August 17, 2005, and their next funding valuation is required by December 31, 2007. Syncrude's most recent funding valuation was prepared as of December 31, 2003, and their next funding valuation is December 31, 2006. 102 Our total benefit payments in 2005 were $8 million for Nexen (2004--$7 million) and nil for Canexus (2004--nil). Our share of Syncrude's total benefit payments in 2005 was $3 million (2004--$3 million). Our estimated future payments are as follows:
-------------------------------------------------------------------------------------------------------------- Define Benefit Other -------------------------------------------------------------------------------------------------------------- Nexen Canexus Syncrude Nexen Canexus Syncrude -------------------------------------------------------------------------------------------------------------- 2006 8 - 3 1 - - -------------------------------------------------------------------------------------------------------------- 2007 9 1 3 1 - - -------------------------------------------------------------------------------------------------------------- 2008 9 1 4 2 - - -------------------------------------------------------------------------------------------------------------- 2009 10 1 4 2 - - -------------------------------------------------------------------------------------------------------------- 2010 11 1 4 2 - - -------------------------------------------------------------------------------------------------------------- 2011-2015 66 13 28 14 - 2 --------------------------------------------------------------------------------------------------------------
17. MARKETING AND OTHER ------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ------------------------------------------------------------------------------------------------------------- Marketing Revenue, Net 847 608 568 ------------------------------------------------------------------------------------------------------------- Change in Fair Value of Crude Oil Put Options (196) 56 - ------------------------------------------------------------------------------------------------------------- Interest 29 12 9 ------------------------------------------------------------------------------------------------------------- Foreign Exchange Gains (Losses) (19) (13) 6 ------------------------------------------------------------------------------------------------------------- Gains on Disposition of Assets (1) 4 24 - ------------------------------------------------------------------------------------------------------------- Other (2) 37 26 27 ------------------------------------------------------------------------------------------------------------- Total Marketing and Other 702 713 610 -------------------------------------------------------------------------------------------------------------
Notes: (1) In 2005, gains on disposition of assets resulted from the sale of minor oil and gas assets by our Nigeria oil and gas business (2004--sale of minor oil and gas assets by our Canadian oil and gas business). (2) In 2005, other includes $2 million (2004--$10 million) of business interruption proceeds received from our insurers. The proceeds result from damage sustained in the Gulf of Mexico during tropical storm Isidore and Hurricane Lili in the third and fourth quarters of 2002. 103 18. INCOME TAXES
(a) TEMPORARY DIFFERENCES --------------------------------------------------------------------------------------------------------------------- 2005 2004 --------------------------------------------------------------------------------------------------------------------- Future Income Future Income Future Income Future Income Tax Tax Tax Tax Assets Liabilities Assets Liabilities --------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment, Net 31 1,785 31 1,852 --------------------------------------------------------------------------------------------------------------------- Tax Losses Carried Forward 370 - 277 - --------------------------------------------------------------------------------------------------------------------- Deferred Income - 175 - 171 --------------------------------------------------------------------------------------------------------------------- Recoverable Taxes 9 - 25 - --------------------------------------------------------------------------------------------------------------------- Total 410 1,960 333 2,023 ---------------------------------------------------------------------------------------------------------------------
(b) CANADIAN AND FOREIGN INCOME TAXES --------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Taxes --------------------------------------------------------------------------------------------------------------------- Canadian (387) 24 (352) --------------------------------------------------------------------------------------------------------------------- Foreign 1,334 1,003 956 --------------------------------------------------------------------------------------------------------------------- 947 1,027 604 --------------------------------------------------------------------------------------------------------------------- Provision for Income Taxes --------------------------------------------------------------------------------------------------------------------- Current --------------------------------------------------------------------------------------------------------------------- Canadian 1 6 5 --------------------------------------------------------------------------------------------------------------------- Foreign 338 242 209 --------------------------------------------------------------------------------------------------------------------- 339 248 214 --------------------------------------------------------------------------------------------------------------------- Future --------------------------------------------------------------------------------------------------------------------- Canadian (203) (3) (180) --------------------------------------------------------------------------------------------------------------------- Foreign 103 72 63 --------------------------------------------------------------------------------------------------------------------- (100) 69 (117) --------------------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------------------- Total Provision for Income Taxes 239 317 97 ---------------------------------------------------------------------------------------------------------------------
The Canadian and foreign components of the provision for income taxes are based on the jurisdiction in which income is taxed. Foreign taxes relate mainly to Yemen, Colombia and the United States and include Yemen cash taxes of $296 million (2004--$227 million; 2003--$201 million).
(c) RECONCILIATION OF EFFECTIVE TAX RATE TO THE CANADIAN FEDERAL TAX RATE -------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 -------------------------------------------------------------------------------------------------------------------- Income before Income Taxes From Continuing Operations 947 1,027 604 -------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------- Provision for Income Taxes Computed at the Canadian Statutory Rate 324 354 224 -------------------------------------------------------------------------------------------------------------------- Add (Deduct) the Tax Effect of: -------------------------------------------------------------------------------------------------------------------- Royalties and Rentals to Provincial Governments 24 20 20 -------------------------------------------------------------------------------------------------------------------- Resource Allowance and Provincial Tax Rebates (24) (29) (35) -------------------------------------------------------------------------------------------------------------------- Lower Tax Rates on Foreign Operations (40) (22) (48) -------------------------------------------------------------------------------------------------------------------- Additional Canadian Tax on Canadian Resource Income 6 7 8 -------------------------------------------------------------------------------------------------------------------- Lower Tax Rates on Capital Gains (54) - - -------------------------------------------------------------------------------------------------------------------- Federal and Provincial Capital Tax 5 6 4 -------------------------------------------------------------------------------------------------------------------- Revaluation of Future Income Tax Liabilities for Reductions in Statutory Rates - (15) (76) -------------------------------------------------------------------------------------------------------------------- Other (2) (4) - -------------------------------------------------------------------------------------------------------------------- Provision for Income Taxes 239 317 97 --------------------------------------------------------------------------------------------------------------------
In 2004 and 2003, the federal and some provincial governments in Canada reduced statutory income tax rates. This reduced our liability and provision for future income taxes by $15 million and $76 million in 2004 and 2003, respectively. 104 (d) AVAILABLE UNUSED TAX LOSSES AND TAX CONTINGENCIES At December 31, 2005 and 2004, we had unused tax losses totalling $965 million and $702 million, respectively, mostly from our UK operations. Nexen's income tax filings are subject to audit by taxation authorities. There are audits in progress and items under review, some of which may increase our tax liability. In addition, we have filed notices of objection with respect to certain issues. While the results of these items cannot be ascertained at this time, we believe we have an adequate provision for income taxes based on available information. At the time of acquisition, Wascana had outstanding taxation issues in dispute from prior taxation years. Wascana disagreed with issues raised and has filed notices of objection. The value of the tax pools acquired at the time of acquisition reflected our evaluation of the potential impact of these issues. 19. CASH FLOWS
(a) CHARGES AND CREDITS TO INCOME NOT INVOLVING CASH ---------------------------------------------------------------------------------------------- 2005 2004 2003 ---------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 1,052 674 914 ---------------------------------------------------------------------------------------------- Stock Based Compensation 411 74 4 ---------------------------------------------------------------------------------------------- Gains on Disposition of Assets (4) (24) - ---------------------------------------------------------------------------------------------- Future Income Taxes (100) 69 (117) ---------------------------------------------------------------------------------------------- Change in Fair Value of Crude Oil Put Options 196 (56) - ---------------------------------------------------------------------------------------------- Non-Cash Items included in Discontinued Operations (325) 132 191 ---------------------------------------------------------------------------------------------- Unamortized Issue Costs on Preferred Securities Redemption - 11 28 ---------------------------------------------------------------------------------------------- Gain on Dilution of Interest in Chemicals Business (193) - - ---------------------------------------------------------------------------------------------- Net Income Attributable to Non-Controlling Interests 8 - - ---------------------------------------------------------------------------------------------- Other 24 26 4 ---------------------------------------------------------------------------------------------- Total 1,069 906 1,024 ---------------------------------------------------------------------------------------------- (B) CHANGES IN NON-CASH WORKING CAPITAL ----------------------------------------------------------------------------------------------- 2005 2004 2003 ----------------------------------------------------------------------------------------------- Accounts Receivable (1,078) (454) (488) ----------------------------------------------------------------------------------------------- Inventories and Supplies (163) (106) (45) ----------------------------------------------------------------------------------------------- Other Current Assets (10) 44 (59) ----------------------------------------------------------------------------------------------- Accounts Payable and Accrued Liabilities 982 650 242 ----------------------------------------------------------------------------------------------- Other 20 (12) 12 ----------------------------------------------------------------------------------------------- Total (249) 122 (338) ----------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------- Relating to: ----------------------------------------------------------------------------------------------- Operating Activities (195) (122) (320) ----------------------------------------------------------------------------------------------- Investing Activities (54) 244 (18) ----------------------------------------------------------------------------------------------- Total (249) 122 (338) ----------------------------------------------------------------------------------------------- (C) OTHER CASH FLOW INFORMATION ----------------------------------------------------------------------------------------------- 2005 2004 2003 ----------------------------------------------------------------------------------------------- Interest Paid 237 190 197 ----------------------------------------------------------------------------------------------- Income Taxes Paid 325 249 211 -----------------------------------------------------------------------------------------------
In 2004, other operating activity cash outflows include $144 million for the purchase of crude oil put options. 105 20. OPERATING SEGMENTS AND RELATED INFORMATION Nexen has the following operating segments in various industries and geographic locations: OIL AND GAS: We explore for, develop and produce crude oil, natural gas and related products around the world. We manage our operations to reflect differences in the regulatory environments and risk factors for each country. Our core operations are onshore in Yemen and Canada, and offshore in the US Gulf of Mexico and the UK North Sea. Our other operations are primarily in West Africa and Colombia. Oil and gas also includes our marketing operations. Marketing sells our own crude oil and natural gas, markets third-party crude oil and natural gas and engages in energy trading. SYNCRUDE: We own 7.23% of the Syncrude Joint Venture, which develops and produces synthetic crude oil from mining bitumen in the oil sands in northern Alberta. CHEMICALS: Through our investment in Canexus, we manufacture, market and distribute industrial chemicals, principally sodium chlorate, chlorine, acid and caustic soda. We produce sodium chlorate at four facilities in Canada and one in Brazil. We produce chlorine, caustic soda and muriatic acid at chlor-alkali facilities in Canada and Brazil. The accounting policies of our operating segments are the same as those described in Note 1. Net income of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses with the exception of Chemicals. Identifiable assets are those used in the operations of the segments. 106
2005 OPERATING AND GEOGRAPHIC SEGMENTS -------------------------------------------------------------------------------------------------------------------------------- Oil and Gas Syncrude(1) Chemicals Corporate Total and Other -------------------------------------------------------------------------------------------------------------------------------- (Cdn$ Other millions) Yemen Canada(2) US UK Countries(3) Marketing -------------------------------------------------------------------------------------------------------------------------------- Net Sales (4) 1,377 455 792 366 119 28 397 398(5) - 3,932 -------------------------------------------------------------------------------------------------------------------------------- Marketing and Other 8 3 2 16 4 847 - 15 (193)(6) 702 -------------------------------------------------------------------------------------------------------------------------------- Gain on Dilution of Interest in Chemicals Business - - - - - - - 193 - 193 -------------------------------------------------------------------------------------------------------------------------------- 1,385 458 794 382 123 875 397 606 (193) 4,827 -------------------------------------------------------------------------------------------------------------------------------- Less: Expenses -------------------------------------------------------------------------------------------------------------------------------- Operating 150 121 96 95 12 30 152 237 - 893 -------------------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 354 140 234 210 13 11 17 51(7) 22 1,052 -------------------------------------------------------------------------------------------------------------------------------- Transportation and Other 6 23 1 - 2 641 21 40 62 796 -------------------------------------------------------------------------------------------------------------------------------- General and Administrative(8) 42 105 84 8 97 89 1 45 321 792 -------------------------------------------------------------------------------------------------------------------------------- Exploration 12 23 100 51 64(9) - - - - 250 -------------------------------------------------------------------------------------------------------------------------------- Interest - - - - - - - 3 94 97 -------------------------------------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 821 46 279 18 (65) 104 206 230 (692) 947 -------------------------------------------------------------------------------------------------------------------------------- Less: Provision for (Recovery of) Income Taxes (10) 285 14 99 7 (12) 41 60 15 (270) 239 -------------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) from Continuing Operations 536 32 180 11 (53) 63 146 215 (422) 708 -------------------------------------------------------------------------------------------------------------------------------- Less: Non-Controlling Interests - - - - - - - 8 - 8 -------------------------------------------------------------------------------------------------------------------------------- Add: Net Income from Discontinued Operations - 452 - - - - - - - 452 -------------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) 536 484 180 11 (53) 63 146 207 (422) 1,152 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Identifiable Assets 635 2,449 1,433 4,775 183 3,165(11) 1,135 482 333 14,590 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Capital Expenditures -------------------------------------------------------------------------------------------------------------------------------- Development and Other 236 947 148 566 14 16 197 14 24 2,162 -------------------------------------------------------------------------------------------------------------------------------- Exploration 41 90 211 59 55 - - - - 456 -------------------------------------------------------------------------------------------------------------------------------- Proved Property Acquisitions - 17 3 - - - - - - 20 -------------------------------------------------------------------------------------------------------------------------------- Total Capital Expenditures 277 1,054 362 625 69 16 197 14 24 2,638 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment -------------------------------------------------------------------------------------------------------------------------------- Cost 2,243 3,631 2,437 4,013 249 177 1,240 827 245 15,062 -------------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A 1,841 1,311 1,159 216 119 72 171 456 123 5,468 -------------------------------------------------------------------------------------------------------------------------------- Net Book Value(4) 402 2,320 1,278 3,797 130 105 1,069 371 122 9,594 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Goodwill -------------------------------------------------------------------------------------------------------------------------------- Cost - - - 325 - 63 - - - 388 -------------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A - - - - - 24 - - - 24 -------------------------------------------------------------------------------------------------------------------------------- Net Book Value - - - 325 - 39 - - - 364 --------------------------------------------------------------------------------------------------------------------------------
Notes: (1) Syncrude is considered a mining operation for US reporting purposes. PP&E at December 31, 2005 includes mineral rights of $6 million. (2) During the third quarter of 2005, we concluded the sale of certain Canadian conventional oil and gas properties. The results of these properties are shown as discontinued operations (see Note 14). (3) Includes results of operations from producing activities in Nigeria and Colombia. (4) Net sales made from all segments originating in Canada: 1,014 PP&E located in Canada: 3,899 (5) Net sales for our chemicals operations include: Canada 132 United States 198 Brazil 68 --- Total 398 (6) Includes interest income of $29 million, foreign exchange losses of $19 million, decrease in the fair value of crude oil put options of $196 million and decrease in the fair value of foreign currency call options of $7 million. (7) Includes impairment charge of $12 million related to the closure of our sodium chlorate plant in Amherstburg, Ontario. (8) Includes stock-based compensation expense of $490 million. (9) Includes exploration activities primarily in Nigeria, Colombia and Equatorial Guinea. (10) The provision for (recovery of) income taxes for foreign locations is based on in-country taxes on foreign income. For oil and gas locations with no operating activities, the provision is based on the tax jurisdiction of the entity performing the activity. (11) Approximately 86% of Marketing's identifiable assets are accounts receivable and inventories. 107
2004 OPERATING AND GEOGRAPHIC SEGMENTS -------------------------------------------------------------------------------------------------------------------------------- Oil and Gas Syncrude(1) Chemicals Corporate Total and Other -------------------------------------------------------------------------------------------------------------------------------- (Cdn$ Other millions) Yemen Canada(2) US UK Countries(3) Marketing -------------------------------------------------------------------------------------------------------------------------------- Net Sales (4) 921 390 811 36 73 14 321 378(5) - 2,944 -------------------------------------------------------------------------------------------------------------------------------- Marketing and Other 5 27 11 - 2 608 - 5 55(6) 713 -------------------------------------------------------------------------------------------------------------------------------- 826 417 822 36 75 622 321 383 55 3,657 -------------------------------------------------------------------------------------------------------------------------------- Less: Expenses -------------------------------------------------------------------------------------------------------------------------------- Operating 109 116 106 6 7 16 125 237 - 722 -------------------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 169 128 258 18 18 10 18 37 18 674 -------------------------------------------------------------------------------------------------------------------------------- Transportation and Other 5 15 - - - 451 12 41 25 549 -------------------------------------------------------------------------------------------------------------------------------- General and Administrative 4 42 30 - 47 58 1 28 89 299 -------------------------------------------------------------------------------------------------------------------------------- Exploration 2 18 138 3 82(7) - - - - 243 -------------------------------------------------------------------------------------------------------------------------------- Interest - - - - - - - - 143 143 -------------------------------------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 637 98 290 9 (79) 87 165 40 (220) 1,027 -------------------------------------------------------------------------------------------------------------------------------- Less: Provision for (Recovery of) Income Taxes (10) 222 28 104 4 1 28 47 13 (130) 317 -------------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) from Continuing Operations 415 70 186 5 (80) 59 118 27 (90) 710 -------------------------------------------------------------------------------------------------------------------------------- Add: Net Income from Discontinued Operations - 70 - - 13 - - - - 83 -------------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) 415 140 186 5 (67) 59 118 27 (90) 793 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Identifiable Assets 564 1,979 1,359 4,446 218 2,030(10) 912 497 378 12,383 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Capital Expenditures -------------------------------------------------------------------------------------------------------------------------------- Development and Other 267 491 267 53 24 4 214 58 33 1,411 -------------------------------------------------------------------------------------------------------------------------------- Exploration 19 46 133 4 64 - - - - 266 -------------------------------------------------------------------------------------------------------------------------------- Proved Property Acquisitions - 4 - - - - - - - 4 -------------------------------------------------------------------------------------------------------------------------------- Total Capital Expenditures 286 541 400 57 88 4 214 58 33 1,681 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment -------------------------------------------------------------------------------------------------------------------------------- Cost 2,038 2,603 2,249 3,499 535 157 1,030 815 201 13,127 -------------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A 1,550 1,195 1,037 16 408 64 155 409 90 4,924 -------------------------------------------------------------------------------------------------------------------------------- Net Book Value(4) 488 1,408 1,212 3,483 127 93 875 406 111 8,203 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Goodwill -------------------------------------------------------------------------------------------------------------------------------- Cost - - - 339 - 60 - - - 399 -------------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A - - - - - 24 - - - 24 -------------------------------------------------------------------------------------------------------------------------------- Net Book Value - - - 339 - 36 - - - 375 --------------------------------------------------------------------------------------------------------------------------------
Notes: (1) Syncrude is considered a mining operation for US reporting purposes. PP&E at December 31, 2004 includes mineral rights of $6 million. (2) On December 1, 2004 we acquired EnCana (UK) Limited (see Note 3). (3) Includes results of operations from producing activities in Nigeria, Colombia, and Australia. (4) Net sales made from all segments originating in Canada: 1,242 PP&E located in Canada: 3,198 (5) Net sales for our chemicals operations include: Canada 135 United States 184 Brazil 59 --- Total 378 (6) Includes interest income of $12 million, foreign exchange losses of $13 million and unrealized mark-to-market gains on crude oil put options of $56 million. (7) Includes exploration activities primarily in Nigeria and Colombia. (8) The provision for (recovery of) income taxes for foreign locations is based on in-country taxes on foreign income. For oil and gas locations with no operating activities, the provision is based on the tax jurisdiction of the entity performing the activity. (9) In the fourth quarter of 2004, we concluded production activities in Australia. During the third quarter of 2005, we concluded the sale of certain Canadian conventional oil and gas properties. The combined results of these dispositions are shown as discontinued operations (see Note 14). (10) Approximately 81% of Marketing's identifiable assets are accounts receivable and inventories. (11) Excludes PP&E costs of $860 million and accumulated DD&A of $420 million relating to the Canadian properties disposed of during 2005 (see Note 14). 108
2003 OPERATING AND GEOGRAPHIC SEGMENTS --------------------------------------------------------------------------------------------------------------------------- Oil and Gas Syncrude(1) Chemicals Corporate Total and Other --------------------------------------------------------------------------------------------------------------------------- (Cdn$ Other millions) Yemen Canada(2) US Countries(3) Marketing -------------------------------------------------------------------------------------------------------------------------- Net Sales (4) 827 397 707 65 21 240 375(5) - 2,632 -------------------------------------------------------------------------------------------------------------------------- Marketing and Other 6 5 14 - 568 - 2 15(6) 610 -------------------------------------------------------------------------------------------------------------------------- 833 402 721 65 589 240 377 15 3,242 -------------------------------------------------------------------------------------------------------------------------- Less: Expenses -------------------------------------------------------------------------------------------------------------------------- Operating 92 110 86 15 22 123 240 - 688 -------------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 168 409(7) 207 38 15 14 46 17 914 -------------------------------------------------------------------------------------------------------------------------- Transportation and Other 5 4 - - 398 11 42 29 489 -------------------------------------------------------------------------------------------------------------------------- General and Administrative 5 22 13 20 43 1 21 60 185 -------------------------------------------------------------------------------------------------------------------------- Exploration 17 28 89 59(8) - - - - 193 -------------------------------------------------------------------------------------------------------------------------- Interest - - - - - - - 169 169 -------------------------------------------------------------------------------------------------------------------------- Income (Loss) from Continuing Operations before Income Taxes 546 (171) 326 (67) 111 91 28 (260) 604 -------------------------------------------------------------------------------------------------------------------------- Less: Provision for (Recovery of) Income Taxes (9) 191 (140) 115 (1) 39 25 10 (142) 97 -------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) from Continuing Operations 355 (31) 211 (66) 72 66 18 (118) 507 -------------------------------------------------------------------------------------------------------------------------- Add: Net Income from Discontinued Operations - 58(10) - 13(11) - - - - 71 -------------------------------------------------------------------------------------------------------------------------- Net Income (Loss) 355 27 211 (53) 72 66 18 (118) 578 -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- Identifiable Assets 574 2,176 1,446 197 1,518(12) 719 475 612 7,717 -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- Capital Expenditures -------------------------------------------------------------------------------------------------------------------------- Development and Other 219 259 249 25 1 195 24 29 1,001 -------------------------------------------------------------------------------------------------------------------------- Exploration 34 51 147 97 - - - - 329 -------------------------------------------------------------------------------------------------------------------------- Proved Property Acquisitions - - 164(13) - - - - - 164 -------------------------------------------------------------------------------------------------------------------------- Total Capital Expenditures 253 310 560 122 1 195 24 29 1,494 -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- Property, Plant and Equipment -------------------------------------------------------------------------------------------------------------------------- Cost 1,898 2,169 2,153 534 158 821 774 168 8,675 -------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A 1,497 1,106 887 410 57 114 381 71 4,553 -------------------------------------------------------------------------------------------------------------------------- Net Book Value (4) 401 1,063(14) 1,266 124 101 677 393 97 4,122 -------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------- Goodwill -------------------------------------------------------------------------------------------------------------------------- Cost - - - - 60 - - - 60 -------------------------------------------------------------------------------------------------------------------------- Less: Accumulated DD&A - - - - 24 - - - 24 -------------------------------------------------------------------------------------------------------------------------- Net Book Value - - - - 36 - - - 36 --------------------------------------------------------------------------------------------------------------------------
Notes: (1) Syncrude is considered a mining operation for US reporting purposes. PP&E at December 31, 2003 includes mineral rights of $6 million. (2) Includes results of operations from producing activities in Nigeria, Colombia and Australia. (3) Includes results of operations from a natural gas-fired generating facility in Alberta. (4) Net sales made from all segments originating in Canada: 1,218 PP&E located in Canada: 2,566 (5) Net sales for our chemicals operations include: Canada 142 United States 179 Brazil 54 --- Total 375 (6) Includes interest income of $9 million and foreign exchange gains of $6 million. (7) Includes impairment charge of $269 million (see Note 6). (8) Includes exploration activities primarily in Nigeria, Colombia, Brazil and Equatorial Guinea. (9) The provision for (recovery of) income taxes for foreign locations is based on in-country taxes on foreign income. For oil and gas locations with no operating activities, the provision is based on the tax jurisdiction of the entity performing the activity. (10) In August 2003, we sold non-core conventional light oil assets in southeast Saskatchewan for net proceeds of $268 million. No gain or loss was recognized on the sale. During the third quarter of 2005, we concluded the sale of certain Canadian conventional oil and gas properties. The combined results of these dispositions are shown as discontinued operations (see Note 14). (11) In the fourth quarter of 2004, we concluded production activities in Australia. These results are shown as discontinued operations (see Note 14). (12) Approximately 80% of Marketing's identifiable assets are accounts receivable and inventories. (13) On March 27, 2003, we acquired the residual 40% interest in Aspen in the Gulf of Mexico for US$109 million. (14) Excludes PP&E costs of $782 million and accumulated DD&A of $354 million relating to the Canadian properties disposed of during 2005 (see Note 14). 109 21. DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. US GAAP Consolidated Financial Statements and summaries of differences from Canadian GAAP are as follows:
CONSOLIDATED STATEMENT OF INCOME--US GAAP FOR THE THREE YEARS ENDED DECEMBER 31, 2005 ------------------------------------------------------------------------------------------------------------------- (Cdn$ millions, except per share amounts) 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------- Revenues and Other Income ------------------------------------------------------------------------------------------------------------------- Net Sales 3,932 2,944 2,632 ------------------------------------------------------------------------------------------------------------------- Marketing and Other (ii); (ix); (x) 687 696 623 ------------------------------------------------------------------------------------------------------------------- Gain on Dilution of Interest in Chemicals Business 193 - - ------------------------------------------------------------------------------------------------------------------- 4,812 3,640 3,255 ------------------------------------------------------------------------------------------------------------------- Expenses ------------------------------------------------------------------------------------------------------------------- Operating (iv) 903 731 694 ------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment (i) 1,081 716 1,027 ------------------------------------------------------------------------------------------------------------------- Transportation and Other (ix) 792 524 489 ------------------------------------------------------------------------------------------------------------------- General and Administrative (viii) 792 263 185 ------------------------------------------------------------------------------------------------------------------- Exploration 250 243 193 ------------------------------------------------------------------------------------------------------------------- Interest 97 143 169 ------------------------------------------------------------------------------------------------------------------- 3,915 2,620 2,757 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Income from Continuing Operations before Income Taxes 897 1,020 498 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Provision for Income Taxes ------------------------------------------------------------------------------------------------------------------- Current 339 248 214 ------------------------------------------------------------------------------------------------------------------- Deferred (i) - (x) (108) 67 (135) ------------------------------------------------------------------------------------------------------------------- 231 315 79 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations before Non-Controlling Interests 666 705 419 ------------------------------------------------------------------------------------------------------------------- Net Income Attributable to Non-Controlling Interests 8 - - ------------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations before Cumulative Effect of Changes in ------------------------------------------------------------------------------------------------------------------- Accounting 658 705 419 Principles ------------------------------------------------------------------------------------------------------------------- Net Income from Discontinued Operations (i) 452 83 49 ------------------------------------------------------------------------------------------------------------------- Cumulative Effect of Changes in Accounting Principles, ------------------------------------------------------------------------------------------------------------------- Net of Income Taxes (vii); (x) - - (48) ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Net Income--US GAAP (1) 1,110 788 420 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share ($/share) ------------------------------------------------------------------------------------------------------------------- Basic (Note 13) ------------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations 2.52 2.74 1.69 ------------------------------------------------------------------------------------------------------------------- Net Income from Discontinued Operations 1.74 0.32 0.20 ------------------------------------------------------------------------------------------------------------------- Cumulative Effect of Changes in Accounting Principles - - (0.19) ------------------------------------------------------------------------------------------------------------------- 4.26 3.06 1.70 ------------------------------------------------------------------------------------------------------------------- Diluted (Note 13) ------------------------------------------------------------------------------------------------------------------- Net Income from Continuing Operations 2.47 2.71 1.68 ------------------------------------------------------------------------------------------------------------------- Net Income from Discontinued Operations 1.70 0.32 0.19 ------------------------------------------------------------------------------------------------------------------- Cumulative Effect of Changes in Accounting Principles - - (0.19) ------------------------------------------------------------------------------------------------------------------- 4.17 3.03 1.68 ------------------------------------------------------------------------------------------------------------------- Note: 1 Reconciliation of Canadian and US GAAP Net Income ------------------------------------------------------------------------------------------------------------------- 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------- Net Income--Canadian GAAP 1,152 793 578 ------------------------------------------------------------------------------------------------------------------- Impact of US Principles, Net of Income Taxes: ------------------------------------------------------------------------------------------------------------------- Fair Value of Preferred Securities (x) - 4 7 ------------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment (i); (vii) (29) (42) (92) ------------------------------------------------------------------------------------------------------------------- Stock Based Compensation Included in Retained Earnings (viii) - 36 - ------------------------------------------------------------------------------------------------------------------- Loss on Disposition (i) - - (22) ------------------------------------------------------------------------------------------------------------------- Other (ii); (iv) (13) (3) (3) ------------------------------------------------------------------------------------------------------------------- Cumulative Effect of Changes in Accounting Principles (vii); (x) - - (48) ------------------------------------------------------------------------------------------------------------------- Net Income--US GAAP 1,110 788 420 -------------------------------------------------------------------------------------------------------------------
110
CONSOLIDATED BALANCE SHEET--US GAAP ------------------------------------------------------------------------------------------------------------------ (Cdn$ millions, except share amounts) December 31, 2005 December 31, 2004 ------------------------------------------------------------------------------------------------------------------ ASSETS ------------------------------------------------------------------------------------------------------------------ Current Assets ------------------------------------------------------------------------------------------------------------------ Cash and Cash Equivalents 48 73 ------------------------------------------------------------------------------------------------------------------ Restricted Cash 70 - ------------------------------------------------------------------------------------------------------------------ Accounts Receivable (ii) 3,151 2,106 ------------------------------------------------------------------------------------------------------------------ Inventories and Supplies 504 351 ------------------------------------------------------------------------------------------------------------------ Assets of Discontinued Operations - 38 ------------------------------------------------------------------------------------------------------------------ 51 41 Other ------------------------------------------------------------------------------------------------------------------ Total Current Assets 3,824 2,609 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ Property, Plant and Equipment ------------------------------------------------------------------------------------------------------------------ Net of Accumulated Depreciation, Depletion, Amortization and ------------------------------------------------------------------------------------------------------------------ Impairment of $5,861 (December 31, 2004--$5,290) (i); (iv); (vii) 9,550 8,198 ------------------------------------------------------------------------------------------------------------------ Goodwill 364 375 ------------------------------------------------------------------------------------------------------------------ Deferred Income Tax Assets 410 333 ------------------------------------------------------------------------------------------------------------------ Deferred Charges and Other Assets (v) 345 384 ------------------------------------------------------------------------------------------------------------------ Assets of Discontinued Operations - 440 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ TOTAL ASSETS 14,493 12,339 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ LIABILITIES AND SHAREHOLDERS' EQUITY ------------------------------------------------------------------------------------------------------------------ Current Liabilities ------------------------------------------------------------------------------------------------------------------ Short-Term Borrowings - 100 ------------------------------------------------------------------------------------------------------------------ Accounts Payable and Accrued Liabilities (ii) 3,745 2,377 ------------------------------------------------------------------------------------------------------------------ Accrued Interest Payable 55 34 ------------------------------------------------------------------------------------------------------------------ Dividends Payable 13 13 ------------------------------------------------------------------------------------------------------------------ Liabilities of Discontinued Operations - 39 ------------------------------------------------------------------------------------------------------------------ Total Current Liabilities 3,813 2,563 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ Long-Term Debt (v) 3,630 4,214 ------------------------------------------------------------------------------------------------------------------ Deferred Income Tax Liabilities (i) - (x) 1,906 1,993 ------------------------------------------------------------------------------------------------------------------ Asset Retirement Obligations (vii) 590 399 ------------------------------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities (vi) 505 148 ------------------------------------------------------------------------------------------------------------------ Liabilities of Discontinued Operations - 130 ------------------------------------------------------------------------------------------------------------------ Non-Controlling Interests 88 - ------------------------------------------------------------------------------------------------------------------ Shareholders' Equity ------------------------------------------------------------------------------------------------------------------ Common Shares, no par value ------------------------------------------------------------------------------------------------------------------ Authorized: Unlimited ------------------------------------------------------------------------------------------------------------------ Outstanding: 2005--261,140,571 shares ------------------------------------------------------------------------------------------------------------------ 2004--258,399,166 shares 732 637 ------------------------------------------------------------------------------------------------------------------ Contributed Surplus 2 - ------------------------------------------------------------------------------------------------------------------ Retained Earnings (i) - (x) 3,418 2,360 ------------------------------------------------------------------------------------------------------------------ Accumulated Other Comprehensive Income (ii); (iii); (vi) (191) (105) ------------------------------------------------------------------------------------------------------------------ Total Shareholders' Equity 3,961 2,892 ------------------------------------------------------------------------------------------------------------------ Commitments, Contingencies and Guarantees ------------------------------------------------------------------------------------------------------------------ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY 14,493 12,339 ------------------------------------------------------------------------------------------------------------------
111
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME--US GAAP FOR THE THREE YEARS ENDED DECEMBER 31, 2005 ------------------------------------------------------------------------------------------------------------------ (Cdn$ millions) 2005 2004 2003 ------------------------------------------------------------------------------------------------------------------ Net Income--US GAAP 1,110 788 420 ------------------------------------------------------------------------------------------------------------------ Other Comprehensive Income, Net of Income Taxes: ------------------------------------------------------------------------------------------------------------------ Translation Adjustment (iii) (56) (72) (127) ------------------------------------------------------------------------------------------------------------------ Unrealized Mark-to-Market Gain (Loss) (ii) (20) 11 (7) ------------------------------------------------------------------------------------------------------------------ Minimum Unfunded Pension Liability (vi) (10) (1) (1) ------------------------------------------------------------------------------------------------------------------ Comprehensive Income 1,024 726 285 ------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF CASH FLOWS Under US GAAP, geological and geophysical costs in 2003 of $62 million included in investing activities would be reported in operating activities. See Note 1(u) to our Consolidated Financial Statements. NOTES TO THE CONSOLIDATED US GAAP FINANCIAL STATEMENTS: i. Under US GAAP, the liability method of accounting for income taxes was adopted in 1993. In Canada, the liability method was adopted in 2000. In 1997, we acquired certain oil and gas assets, and the amount paid for these assets differed from the tax basis acquired. Under US principles, this difference was recorded as a deferred tax liability with an increase to PP&E rather than a charge to retained earnings. As a result: o additional depreciation, depletion, amortization and impairment of $29 million (2004--$42 million; 2003--$92 million) was included in net income; and o PP&E is higher under US GAAP at December 31, 2004 by $29 million. During the third quarter of 2003, some of these assets were sold as described in Note 14. With the carrying value of these assets higher under US GAAP, the sale resulted in a loss on disposition of $22 million, net of income taxes of $10 million. This loss was included in our 2003 net income from discontinued operations disclosed on the Consolidated Statement of Income--US GAAP. Included in depreciation, depletion, amortization and impairment expense for 2003 is an impairment charge of $315 million. The amount is higher under US GAAP as we have higher US GAAP carrying values for the assets impaired resulting from differences in adopting the liability method of accounting for income taxes as previously described. ii. Under US GAAP, all derivative instruments are recognized on the balance sheet as either an asset or a liability measured at fair value. Changes in the fair value of derivatives are recognized in earnings unless specific hedge criteria are met. CASH FLOW HEDGES Changes in the fair value of derivatives that are designated as cash flow hedges are recognized in net income in the same period as the hedged item. Any fair value change in a derivative before that period is recognized on the balance sheet. The effective portion of that change is recognized in other comprehensive income with any ineffectiveness recognized in net income. Future sale of oil and gas production: Included in accounts payable at December 31, 2003, was a $3 million loss on forward contracts we used to hedge commodity price risk on the future sale of a portion of our production from the Aspen field. These contracts expired in March 2004. Losses ($2 million, net of income taxes), that were deferred in accumulated other comprehensive income (AOCI) at December 31, 2003, were recognized in net sales in 2004. Future sale of gas inventory: Included in accounts payable at December 31, 2003, was $11 million of losses on futures and basis swap contracts we used to hedge commodity price risk on the future sale of our gas inventory. These contracts effectively lock-in profits on our stored gas volumes. Losses of $8 million ($5 million, net of income taxes) related to the effective portion and deferred in AOCI at December 31, 2003, were recognized in marketing and other in 2004. Additionally, losses of $3 million ($2 million, net of income taxes), related to the ineffective portion, were recognized in marketing and other under US GAAP in 2003. Under Canadian GAAP, the ineffective portion was recognized in net income in 2004. Included in accounts receivable at December 31, 2004, were $6 million of gains on futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory as described in Note 7. These contracts effectively lock-in profits on our stored gas volumes. Gains of $6 million ($4 112 million, net of income taxes) related to the effective portion and deferred in AOCI at December 31, 2004, were recognized in marketing and other during the first quarter of 2005. At December 31, 2005, losses of $35 million were included in accounts payable with respect to futures contracts and swaps we used to hedge commodity price risk on the future sale of our gas inventory as described in Note 7. Losses of $24 million ($16 million, net of income taxes) related to the effective portion have been deferred in AOCI until the underlying gas inventory is sold. These losses will be reclassified to marketing and other as the contracts settle over the next 12 months. The ineffective portion of the losses of $11 million ($7 million, net of income taxes) was recognized in net income during the year. FAIR VALUE HEDGES Both the derivative instrument and the underlying commitment are recognized on the balance sheet at their fair value. The change in fair value of both are reflected in net income. At December 31, 2005, we had no fair value hedges in place. iii. Under US GAAP, exchange gains and losses arising from the translation of our net investment in self-sustaining foreign operations are included in comprehensive income. Additionally, exchange gain and losses, net of income taxes, from the translation of our US-dollar long-term debt designated as a hedge of our foreign net investment are included in comprehensive income. Cumulative amounts are included in AOCI in the Consolidated Balance Sheet--US GAAP. iv. Under Canadian GAAP, we defer certain development costs and all pre-operating revenues and costs to PP&E. Under US GAAP, these costs have been included in operating expenses. As a result: o operating expenses include pre-operating costs of $10 million ($6 million, net of income taxes) (2004--$9 million ($6 million net of income taxes); 2003--$4 million ($2 million, net of income taxes)); and o PP&E is lower under US GAAP by $25 million (December 31, 2004--$15 million). v. Under US GAAP, discounts on long-term debt are classified as a reduction of long-term debt rather than as deferred charges and other assets. Discounts of $57 million (December 31, 2004--$45 million) have been included in long-term debt. vi. Under US GAAP, the amount by which our accrued pension cost is less than the unfunded accumulated benefit obligation is included in AOCI and accrued pension liabilities. As a result, deferred credits and other liabilities are higher by $26 million (2004--$6 million) and deferred charges and other assets are higher by $4 million (2004--nil). In 2005, AOCI decreased by $10 million, net of $6 million of income taxes. vii. On January 1, 2003, we adopted FASB Statement No. 143, Accounting for Asset Retirement Obligations (FAS 143) for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent, except for the adoption date, which resulted in our PP&E under US GAAP being lower by $19 million. This change in accounting policy has been reported as a cumulative effect adjustment in the Consolidated Statement of Income--US GAAP as a loss of $37 million, net of income taxes of $25 million, on January 1, 2003. viii. As described in Note 12(c), our existing stock option plan was modified to a tandem option plan in 2004 to include a cash feature. Prior to the modification of our stock option plan, we accounted for stock options using the fair-value method. Following the addition of the cash feature, we account for stock options using the intrinsic-value method. As a result of the plan modification, we recognized an obligation of $85 million for our tandem options under both Canadian and US GAAP. This resulted in a one-time, non-cash expense to net income for Canadian GAAP purposes of $54 million, net of tax, in the second quarter of 2004. For US GAAP purposes, $36 million of this expense was recognized as a reduction of US GAAP retained earnings and $18 million was recognized as an expense to our second quarter 2004 US GAAP net income. The reduction of US GAAP retained earnings was made in respect of stock options granted prior to the adoption of FAS 123 on January 1, 2003. ix. Under US GAAP, gains and losses on the disposition of assets are shown as other expense. Gains of $4 million (2004--$24 million; 2003--$nil) were reclassed from marketing and other to transportation and other. 113 x. In May 2003, the FASB issued Statement No. 150, Accounting for Certain Instruments with Characteristics of Both Liabilities and Equity that requires certain financial instruments, including our preferred securities, to be valued at fair value with changes in fair value recognized through net income.
------------------------------------------------------------------------------------------------------------ Net Gain (Cdn$ millions) Gain (Loss) Tax (Loss) ------------------------------------------------------------------------------------------------------------ Fair Value Change up to June 30, 2003 (2) (16) 5 (11) ------------------------------------------------------------------------------------------------------------ Fair Value Change from July 1, 2003 to December 31, 2003 (1) 12 (5) 7 ------------------------------------------------------------------------------------------------------------ Fair Value Change from January 1, 2004 to February 9, 2004 (1), (3) 4 - 4 ------------------------------------------------------------------------------------------------------------
Notes: (1) Included in marketing and other. (2) Reported as cumulative effect of a change in accounting principle. (3) Redemption date of preferred securities. NEW ACCOUNTING PRONOUNCEMENTS In November 2004, the Financial Accounting Standards Board (FASB) issued Statement 151, Inventory Costs. This statement amends ARB 43 to clarify that: o abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage) should be recognized as current-period charges; and o requires the allocation of fixed production overhead to inventory based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. We do not expect the adoption of this statement will have any material impact on our results of operations or financial position. In December 2004, the FASB issued Statement 123(R), Share-Based Payments. This statement revises Statement 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion 25, Accounting for Stock Issued to Employees. Statement 123(R) requires all stock-based awards issued to employees to be measured at fair value and to be expensed in the income statement. This statement is effective for fiscal years beginning after June 15, 2005. We are currently expensing stock-based awards issued to employees using the fair-value method for equity based awards and the intrinsic method for liability-based awards. Adoption of this standard will change our expense under US GAAP for tandem options and stock appreciation rights as these awards will be measured using the fair-value method rather than the intrinsic method. Upon implementing the new rules, we expect to record an expense for US GAAP purposes of $3 million ($2 million net of income taxes) in 2006, reflecting the cumulative effect of the change in accounting policy. In December 2004, the FASB issued Statement 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29, Accounting for Nonmonetary Transactions. This amendment eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. Under Statement 153, if a nonmonetary exchange of similar productive assets meets a commercial-substance criterion and fair value is determinable, the transaction must be accounted for at fair value resulting in recognition of any gain or loss. This statement is effective for nonmonetary transactions in fiscal periods that begin after June 15, 2005. The adoption of this statement will not have any material impact on our results of operations or financial position. In March 2005, the FASB issued Financial Interpretation 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Statement No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption of this statement has not had a material impact on our results of operations or financial position. In March 2005, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-6, Accounting for Stripping Costs Incurred during Production in the Mining Industry. In the mining industry, companies may be required to remove overburden and other mine waste materials to access mineral deposits. 114 The EITF concluded that the costs of removing overburden and waste materials, often referred to as "stripping costs", incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In June 2005, the FASB issued Statement 154, Accounting Changes and Error Corrections which replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. In the absence of explicit transition provisions provided for in new or existing accounting pronouncements, Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to do so. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. In September 2005, the EITF reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This issue addresses the question of when it is appropriate to measure purchase and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. The consensus should be applied to new arrangements entered into, and modifications or renewals of existing agreements, beginning with the second quarter of 2006. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position. 115 SUPPLEMENTARY DATA (UNAUDITED)
QUARTERLY FINANCIAL DATA IN ACCORDANCE WITH CANADIAN AND US GAAP ----------------------------------------------------------------------------------------------------------------------------- Quarter Ended ----------------------------------------------------------------------------------------------------------------------------- March 31 June 30 September 30 December 31 ----------------------------------------------------------------------------------------------------------------------------- (Cdn$ millions) 2005 2004 2005 2004 2005 2004 2005 2004 ----------------------------------------------------------------------------------------------------------------------------- Net Sales (1) 856 664 909 697 1,094 778 1,073 805 ----------------------------------------------------------------------------------------------------------------------------- Operating Profit is Comprised of: (1), (2), (3), (4), (5) ----------------------------------------------------------------------------------------------------------------------------- Oil and Gas 282 243 250 199 173 296 498 304 ----------------------------------------------------------------------------------------------------------------------------- Syncrude 19 40 59 40 78 52 50 33 ----------------------------------------------------------------------------------------------------------------------------- Chemicals 7 10 (2) 6 215 11 10 13 ----------------------------------------------------------------------------------------------------------------------------- 308 293 307 245 466 359 558 350 ----------------------------------------------------------------------------------------------------------------------------- Net Income from Continuing ----------------------------------------------------------------------------------------------------------------------------- Operations--Canadian GAAP (6) 19 167 170 117 211 200 300 226 ----------------------------------------------------------------------------------------------------------------------------- US GAAP Adjustments (11) (20) (12) 39 (15) (12) (4) (12) ----------------------------------------------------------------------------------------------------------------------------- Net Income from Continuing ----------------------------------------------------------------------------------------------------------------------------- Operations--US GAAP 8 147 158 156 196 188 296 214 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Net Income--Canadian GAAP 37 184 200 143 615 220 300 246 ----------------------------------------------------------------------------------------------------------------------------- US GAAP Adjustments (11) (20) (12) 39 (15) (12) (4) (12) ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Net Income--US GAAP 26 164 188 182 600 208 296 234 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Earnings per Common Share from ----------------------------------------------------------------------------------------------------------------------------- Continuing Operations ($/share) ----------------------------------------------------------------------------------------------------------------------------- Canadian GAAP--Basic 0.08 0.66 0.65 0.45 0.81 0.77 1.15 0.87 ----------------------------------------------------------------------------------------------------------------------------- Canadian GAAP--Diluted 0.08 0.66 0.64 0.44 0.79 0.76 1.12 0.86 ----------------------------------------------------------------------------------------------------------------------------- US GAAP--Basic 0.03 0.58 0.61 0.61 0.75 0.73 1.13 0.82 ----------------------------------------------------------------------------------------------------------------------------- US GAAP--Diluted 0.03 0.57 0.60 0.60 0.73 0.72 1.11 0.82 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Earnings per Common Share ($/share) ----------------------------------------------------------------------------------------------------------------------------- Canadian GAAP--Basic 0.15 0.73 0.77 0.55 2.36 0.85 1.15 0.95 ----------------------------------------------------------------------------------------------------------------------------- Canadian GAAP--Diluted 0.15 0.72 0.76 0.54 2.30 0.84 1.12 0.94 ----------------------------------------------------------------------------------------------------------------------------- US GAAP--Basic 0.10 0.64 0.72 0.71 2.31 0.81 1.13 0.90 ----------------------------------------------------------------------------------------------------------------------------- US GAAP--Diluted 0.10 0.63 0.71 0.70 2.25 0.80 1.11 0.89 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Dividends Declared (7) 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 ----------------------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------------------- Common Share Prices ($/share) ----------------------------------------------------------------------------------------------------------------------------- Toronto Stock Exchange--High 35.50 26.68 39.85 28.25 60.67 26.85 59.54 29.33 ----------------------------------------------------------------------------------------------------------------------------- Toronto Stock Exchange--Low 23.55 22.50 29.53 23.40 40.25 22.17 43.77 24.09 ----------------------------------------------------------------------------------------------------------------------------- New York Stock Exchange--High (US$) 29.18 20.31 32.32 21.15 51.73 21.07 51.69 23.28 ----------------------------------------------------------------------------------------------------------------------------- New York Stock Exchange--Low (US$) 19.44 17.05 23.28 17.25 31.95 16.94 36.80 19.60 -----------------------------------------------------------------------------------------------------------------------------
Notes: (1) Excludes results of certain Canadian conventional oil and gas properties sold in the third quarter of 2005 in southeast Saskatchewan, northwest Saskatchewan, northeast British Columbia and the Alberta foothills, the 2003 sale of non-core conventional light oil assets in southeast Saskatchewan and conclusion of production from our Buffalo field, offshore Australia in 2004. These results are shown as discontinued operations (see Note 14 to the Consolidated Financial Statements). (2) Plant turnarounds and coker maintenance at Syncrude in the fourth quarter of 2004 and first quarter of 2005 increased operating costs and temporarily reduced production volumes. (3) In 2004, a gain of $24 million was recorded on the sale of minor assets by our Canadian oil and gas business. (4) Chemicals operating profit includes a dilution gain of $193 million in the third quarter of 2005 as the result of the Canexus initial public offering. (5) Operating profit is defined as income (loss) from continuing operations before income taxes. (6) Includes the impact of changes in accounting policies as described in Note 1(u) to the Consolidated Financial Statements. (7) In February 2006, the Board of Directors declared a regular quarterly dividend of $0.05 per common share, payable April 1, 2006, to shareholders of record on March 10, 2006. (8) At December 31, 2005, there were 1,294 registered holders of common shares and 261,140,571 common shares outstanding. 116 OIL AND GAS PRODUCING ACTIVITIES AND SYNCRUDE OPERATIONS (UNAUDITED) The following oil and gas information is provided in accordance with the FASB Statement No. 69 Disclosures about Oil and Gas Producing Activities. It also includes information relating to our interest in Syncrude as it produces a crude oil product similar to our oil and gas activities even though these operations are considered mining activities under SEC regulations. A. RESERVE QUANTITY INFORMATION Our net proved reserves and changes in those reserves for our conventional operations (excluding Syncrude) are disclosed below. The net proved reserves represent management's best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year, and at least 80% of the reserves (including Syncrude) have been assessed by independent qualified reserves consultants. Estimates of crude oil and natural gas proved reserves are determined through analysis of geological and engineering data, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. See Critical Accounting Estimates in Item 7 for a description of our reserves estimation process.
-------------------------------------------------------------------------------------------------------------------------------- Other United Countries Total Yemen (1) Canada United States Kingdom (3) -------------------------------------------------------------------------------------------------------------------------------- Conventional oil and bitumen are in mmbbls and natural gas Bitumen is in bcf Oil Gas Oil Oil Gas (2) Oil Gas Oil Gas Oil -------------------------------------------------------------------------------------------------------------------------------- Proved Developed and Undeveloped Reserves (4) -------------------------------------------------------------------------------------------------------------------------------- December 31, 2002 324 803 100 155 524 1 58 279 - - 10 -------------------------------------------------------------------------------------------------------------------------------- Extensions and Discoveries 48 33 36 10 20 - 1 13 - - 1 -------------------------------------------------------------------------------------------------------------------------------- Purchases of Reserves in Place 19 21 - - - - 19 21 - - - -------------------------------------------------------------------------------------------------------------------------------- Sales of Reserves in Place (24) (7) - (24) (6) - - (1) - - - -------------------------------------------------------------------------------------------------------------------------------- Revisions of Previous Estimates (31) (99) (5) (31) (88) 3 (2) (11) - - 4 -------------------------------------------------------------------------------------------------------------------------------- Production (47) (90) (21) (13) (45) - (9) (45) - - (4) -------------------------------------------------------------------------------------------------------------------------------- December 31, 2003 289 661 110 97 405 4 67 256 - - 11 -------------------------------------------------------------------------------------------------------------------------------- Extensions and Discoveries 244 33 1 3 18 239 1 15 - - - -------------------------------------------------------------------------------------------------------------------------------- Purchases of Reserves in Place 127 23 - 1 - - - - 126 23 - -------------------------------------------------------------------------------------------------------------------------------- Sales of Reserves in Place (1) (3) - (1) (2) - - (1) - - - -------------------------------------------------------------------------------------------------------------------------------- Revisions of Previous Estimates (265) (25) (12) (11) (7) (243) (6) (9) 3 (9) 4 -------------------------------------------------------------------------------------------------------------------------------- Production (43) (89) (19) (10) (42) - (10) (46) (1) (1) (3) -------------------------------------------------------------------------------------------------------------------------------- December 31, 2004 351 600 80 79 372 - 52 215 128 13 12 -------------------------------------------------------------------------------------------------------------------------------- Extensions and Discoveries 15 111 5 4 47 - 1 57 5 7 - -------------------------------------------------------------------------------------------------------------------------------- Purchases of Reserves in Place 2 - - 2 - - - - - - - -------------------------------------------------------------------------------------------------------------------------------- Sales of Reserves in Place (28) (80) - (28) (80) - - - - - - -------------------------------------------------------------------------------------------------------------------------------- Revisions of Previous Estimates 9 (18) (3) 2 3 - (5) (21) 15 - - -------------------------------------------------------------------------------------------------------------------------------- Production (45) (81) (23) (9) (37) - (7) (36) (5) (8) (1) -------------------------------------------------------------------------------------------------------------------------------- December 31, 2005 304 532 59 50 305 - 41 215 143 12 11 -------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------- Proved Developed Reserves (5) -------------------------------------------------------------------------------------------------------------------------------- December 31, 2003 216 576 63 87 367 4 54 209 - - 8 -------------------------------------------------------------------------------------------------------------------------------- December 31, 2004 199 518 49 72 348 - 48 166 20 4 10 -------------------------------------------------------------------------------------------------------------------------------- December 31, 2005 154 438 46 44 275 - 37 161 17 2 10 --------------------------------------------------------------------------------------------------------------------------------
Notes: (1) Under the terms of the Masila and the Block 51 production sharing contracts, production is divided into cost recovery oil and profit oil. Cost recovery oil provides for the recovery of all our costs and those of our partners. Remaining production is profit oil, which is shared between the partners and the Government of Yemen based on production rates, with the partners' share ranging from 20% to 33%. The Government's share of profit oil represents its royalty interest and an amount for income taxes payable in Yemen. Yemen's net proved reserves have been determined using the economic interest method and include our share of future cost recovery and profit oil after the Government's royalty interest, but before reserves relating to income taxes payable. Under this method, reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices. Production includes volumes used for fuel. (2) Represents bitumen reserves from the insitu recovery of Canadian oil sands, rather than upgraded synthetic crude oil reserves to be sold. (3) Represents reserves in Australia, Nigeria and Colombia. (4) Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and natural gas liquids 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 test. (5) Proved developed oil and gas reserves are expected to be recovered through existing wells with existing equipment and operating methods. 117 Our net proved reserves and changes in those reserves for our Syncrude operations are disclosed below. Additional disclosures required by SEC Industry Guide 7 are on pages 18 - 20. The net proved reserves represent management's best estimate of proved synthetic reserves after royalties. Reserve estimates are prepared internally each year, and at least 80% of our reserves (including oil and gas activities) have been assessed by independent qualified reserves consultants. Estimates of Syncrude's synthetic crude oil reserves are based on detailed geological and engineering assessments of the bitumen volume in-place, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. In accordance with the approved mining plan, there are an estimated 1,960 million tons of economically extractable oil sands in the Base and North Mines, with an average bitumen grade of 10.6 weight percent. The Aurora North Mine contains an estimated 4,370 million tons of economically extractable oil sands at an average bitumen grade of 11.2 weight percent. Aurora South Lease 31 contains measured economically extractable oil sands of 3,915 million tons at an average bitumen grade of 10.8 weight percent.
--------------------------------------------------------------------------------------------- Synthetic Crude Oil --------------------------------------------------------------------------------------------- Base Mine and (millions of barrels) North Mine (1) Aurora (2) Total --------------------------------------------------------------------------------------------- December 31, 2002 58 168 226 --------------------------------------------------------------------------------------------- Revision of Previous Estimates 1 4 5 --------------------------------------------------------------------------------------------- Extensions and Discoveries - 22 22 --------------------------------------------------------------------------------------------- Production (4) (1) (5) --------------------------------------------------------------------------------------------- December 31, 2003 55 193 248 --------------------------------------------------------------------------------------------- Revision of Previous Estimates (1) (5) (6) --------------------------------------------------------------------------------------------- Extensions and Discoveries - 19 19 --------------------------------------------------------------------------------------------- Production (4) (2) (6) --------------------------------------------------------------------------------------------- December 31, 2004 50 205 255 --------------------------------------------------------------------------------------------- Revision of Previous Estimates - (4) (4) --------------------------------------------------------------------------------------------- Extensions and Discoveries - 19 19 --------------------------------------------------------------------------------------------- (3) (3) (6) Production --------------------------------------------------------------------------------------------- December 31, 2005 47 217 264 ---------------------------------------------------------------------------------------------
Notes: (1) Leases 17 and 22 (2) Leases 10, 12, 31 and 34. 118
B. CAPITALIZED COSTS (EXCLUDING SYNCRUDE OPERATIONS) --------------------------------------------------------------------------------------------------------- Accumulated Depreciation, Depletion, Proved Unproved Amortization and Properties Properties Impairment Capitalized Costs --------------------------------------------------------------------------------------------------------- (Cdn$ millions) --------------------------------------------------------------------------------------------------------- December 31, 2005 --------------------------------------------------------------------------------------------------------- Yemen 2,243 - 1,841 402 --------------------------------------------------------------------------------------------------------- Canada 3,463 143 1,330 2,276 --------------------------------------------------------------------------------------------------------- United States 2,323 114 1,159 1,278 --------------------------------------------------------------------------------------------------------- United Kingdom 3,603 410 216 3,797 --------------------------------------------------------------------------------------------------------- Other Countries 88 161 119 130 --------------------------------------------------------------------------------------------------------- Total Capitalized Costs 11,720 828 4,665 7,883 --------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------- December 31, 2004 --------------------------------------------------------------------------------------------------------- 2,022 16 1,550 488 Yemen --------------------------------------------------------------------------------------------------------- 3,732 136 2,025 1,843 Canada --------------------------------------------------------------------------------------------------------- United States 2,102 147 1,037 1,212 --------------------------------------------------------------------------------------------------------- United Kingdom 3,117 382 16 3,483 --------------------------------------------------------------------------------------------------------- Other Countries 437 98 408 127 --------------------------------------------------------------------------------------------------------- Total Capitalized Costs 11,410 779 5,036 7,153 --------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------- December 31, 2003 --------------------------------------------------------------------------------------------------------- 1,881 17 1,497 401 Yemen --------------------------------------------------------------------------------------------------------- 3,271 129 1,863 1,537 Canada --------------------------------------------------------------------------------------------------------- United States 2,034 123 892 1,265 --------------------------------------------------------------------------------------------------------- Other Countries 454 85 420 119 --------------------------------------------------------------------------------------------------------- Total Capitalized Costs 7,640 354 4,672 3,322 ---------------------------------------------------------------------------------------------------------
C. COSTS INCURRED (EXCLUDING SYNCRUDE OPERATIONS) --------------------------------------------------------------------------------------------------------- Oil and Gas --------------------------------------------------------------------------------------------------------- Total Oil United United (Cdn$ millions) and Gas Yemen Canada States Kingdom Other --------------------------------------------------------------------------------------------------------- Year Ended December 31, 2005 --------------------------------------------------------------------------------------------------------- Property Acquisition Costs --------------------------------------------------------------------------------------------------------- Proved 20 - 17 3 - - --------------------------------------------------------------------------------------------------------- Unproved 15 - - 9 6 - --------------------------------------------------------------------------------------------------------- Exploration Costs 509 44 97 235 61 72 --------------------------------------------------------------------------------------------------------- Development Costs 1,896 236 947 139 560 14 --------------------------------------------------------------------------------------------------------- Asset Retirement Costs 196 13 58 45 80 - --------------------------------------------------------------------------------------------------------- Total Costs Incurred 2,636 293 1,119 431 707 86 --------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------- Year Ended December 31, 2004 --------------------------------------------------------------------------------------------------------- Property Acquisition Costs --------------------------------------------------------------------------------------------------------- Proved 1,774 - 4 - 1,770 - --------------------------------------------------------------------------------------------------------- Unproved 1,491 - - - 1,491 - --------------------------------------------------------------------------------------------------------- Exploration Costs 339 22 56 162 4 95 --------------------------------------------------------------------------------------------------------- Development Costs 1,102 267 491 267 53 24 --------------------------------------------------------------------------------------------------------- Asset Retirement Costs 168 3 27 4 134 - --------------------------------------------------------------------------------------------------------- Total Costs Incurred 4,874 292 578 433 3,452 119 --------------------------------------------------------------------------------------------------------- --------------------------------------------------------------------------------------------------------- Year Ended December 31, 2003 --------------------------------------------------------------------------------------------------------- Property Acquisition Costs --------------------------------------------------------------------------------------------------------- Proved 164 - - 164 - - --------------------------------------------------------------------------------------------------------- Unproved 38 - - 38 - - --------------------------------------------------------------------------------------------------------- Exploration Costs 291 34 51 109 - 97 --------------------------------------------------------------------------------------------------------- Development Costs 752 219 259 249 - 25 --------------------------------------------------------------------------------------------------------- Asset Retirement Costs 185 - 69 62 - 54 --------------------------------------------------------------------------------------------------------- Total Costs Incurred 1,430 253 379 622 - 176 ---------------------------------------------------------------------------------------------------------
119
D. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (EXCLUDING SYNCRUDE OPERATIONS) ------------------------------------------------------------------------------------------------------------- Oil and Gas ------------------------------------------------------------------------------------------------------------- Other Total Oil Yemen Canada United United Countries (Cdn$ millions) and Gas (1) States Kingdom (1) ------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2005 ------------------------------------------------------------------------------------------------------------- Net Sales 3,263 1,377 609 792 366 119 ------------------------------------------------------------------------------------------------------------- Production Costs 511 150 158 96 95 12 ------------------------------------------------------------------------------------------------------------- Exploration Expense 251 12 24 100 51 64 ------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 1,008 354 197 234 210 13 ------------------------------------------------------------------------------------------------------------- Other Expenses (Income) 335 40 125 83 (8) 95 ------------------------------------------------------------------------------------------------------------- 1,158 821 105 279 18 (65) ------------------------------------------------------------------------------------------------------------- Income Tax Provision (Recovery) 411 285 32 99 7 (12) ------------------------------------------------------------------------------------------------------------- Results of Operations 747 536 73 180 11 (53) ------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2004 ------------------------------------------------------------------------------------------------------------- Net Sales 2,538 921 622 811 36 148 ------------------------------------------------------------------------------------------------------------- Production Costs 437 109 156 106 6 60 ------------------------------------------------------------------------------------------------------------- Exploration Expense 246 2 21 138 3 82 ------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 712 169 240 258 18 27 ------------------------------------------------------------------------------------------------------------- Other Expenses (Income) 106 4 38 19 - 45 ------------------------------------------------------------------------------------------------------------- 1,037 637 167 290 9 (66) ------------------------------------------------------------------------------------------------------------- Income Tax Provision (Recovery) 406 222 75 104 4 1 ------------------------------------------------------------------------------------------------------------- Results of Operations 631 415 92 186 5 (67) ------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------- Year Ended December 31, 2003 ------------------------------------------------------------------------------------------------------------- Net Sales 2,338 827 675 707 - 129 ------------------------------------------------------------------------------------------------------------- Production Costs 382 92 159 86 - 45 ------------------------------------------------------------------------------------------------------------- Exploration Expense 201 17 35 89 - 60 ------------------------------------------------------------------------------------------------------------- Depreciation, Depletion, Amortization and Impairment 945 168 510 207 - 60 ------------------------------------------------------------------------------------------------------------- Other Expenses (Income) 49 4 26 (1) - 20 ------------------------------------------------------------------------------------------------------------- 761 546 (55) 326 - (56) ------------------------------------------------------------------------------------------------------------- Income Tax Provision (Recovery) 221 191 (82) 115 - (3) ------------------------------------------------------------------------------------------------------------- Results of Operations 540 355 27 211 - (53) -------------------------------------------------------------------------------------------------------------
Note: (1) Includes results of discontinued operations (see Note 14). E. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN (EXCLUDING SYNCRUDE OPERATIONS) The following disclosure is based on estimates of net proved reserves (excluding Syncrude) and the period during which they are expected to be produced. Future cash inflows are computed by applying year-end prices to our after royalty share of estimated annual future production from proved oil and gas reserves (excluding Syncrude operations). Future development and production costs to be incurred in producing and further developing the proved reserves are based on year-end cost indicators. Future income taxes are computed by applying year-end statutory-tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows. Discounted future net cash flows are calculated using 10% mid-period discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results. We believe this information does not in any way reflect the current economic value of our oil and gas producing properties or the present value of their estimated future cash flows as: o no economic value is attributed to probable and possible reserves; o use of a 10% discount rate is arbitrary; and o prices change constantly from year-end levels.
----------------------------------------------------------------------------------------------------------------- United United Other (Cdn$ millions) Total Yemen Canada States Kingdom Countries ----------------------------------------------------------------------------------------------------------------- December 31, 2005 ----------------------------------------------------------------------------------------------------------------- Future Cash Inflows 23,040 3,675 4,558 5,002 9,190 615 ----------------------------------------------------------------------------------------------------------------- Future Production Costs 5,477 807 1,886 811 1,892 81 ----------------------------------------------------------------------------------------------------------------- Future Development Costs 1,093 153 124 268 534 14 ----------------------------------------------------------------------------------------------------------------- Future Dismantlement and Site ----------------------------------------------------------------------------------------------------------------- Restoration Costs, Net 778 20 180 193 381 4 ----------------------------------------------------------------------------------------------------------------- Future Income Tax 4,496 795 244 1,107 2,172 178 ----------------------------------------------------------------------------------------------------------------- Future Net Cash Flows 11,196 1,900 2,124 2,623 4,211 338 ----------------------------------------------------------------------------------------------------------------- 10% Discount Factor 3,154 338 811 697 1,209 99 ----------------------------------------------------------------------------------------------------------------- Standardized Measure 8,042 1,562 1,313 1,926 3,002 239 ----------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------- December 31, 2004 ----------------------------------------------------------------------------------------------------------------- Future Cash Inflows 18,950 3,779 4,747 4,085 5,852 487 ----------------------------------------------------------------------------------------------------------------- Future Production Costs 4,781 722 2,135 613 1,271 40 ----------------------------------------------------------------------------------------------------------------- Future Development Costs 1,477 275 100 185 903 14 ----------------------------------------------------------------------------------------------------------------- Future Dismantlement and Site ----------------------------------------------------------------------------------------------------------------- Restoration Costs, Net 626 4 149 129 336 8 ----------------------------------------------------------------------------------------------------------------- Future Income Tax 2,798 388 382 845 1,058 125 ----------------------------------------------------------------------------------------------------------------- Future Net Cash Flows 9,268 2,390 1,981 2,313 2,284 300 ----------------------------------------------------------------------------------------------------------------- 10% Discount Factor 2,978 499 760 631 1,011 77 ----------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------- Standardized Measure 6,290 1,891 1,221 1,682 1,273 223 ----------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------- December 31, 2003 ----------------------------------------------------------------------------------------------------------------- Future Cash Inflows 14,660 4,416 5,319 4,470 - 455 ----------------------------------------------------------------------------------------------------------------- Future Production Costs 3,651 868 1,980 666 - 137 ----------------------------------------------------------------------------------------------------------------- Future Development Costs 788 412 102 249 - 25 ----------------------------------------------------------------------------------------------------------------- Future Dismantlement and Site ----------------------------------------------------------------------------------------------------------------- Restoration Costs, Net 309 - 112 137 - 60 ----------------------------------------------------------------------------------------------------------------- Future Income Tax 2,152 574 656 854 - 68 ----------------------------------------------------------------------------------------------------------------- Future Net Cash Flows 7,760 2,562 2,469 2,564 - 165 ----------------------------------------------------------------------------------------------------------------- 10% Discount Factor 2,243 620 879 691 - 53 ----------------------------------------------------------------------------------------------------------------- Standardized Measure 5,517 1,942 1,590 1,873 - 112 -----------------------------------------------------------------------------------------------------------------
CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The following are the principal sources of change in the standardized measure of discounted future net cash flows:
-------------------------------------------------------------------------------------------------------------------- (Cdn$ 2005 2004 2003 millions) -------------------------------------------------------------------------------------------------------------------- Beginning of Year 6,290 5,517 6,369 -------------------------------------------------------------------------------------------------------------------- Sales and Transfers of Oil and Gas Produced, Net of Production Costs (2,028) (1,674) (2,298) -------------------------------------------------------------------------------------------------------------------- Net Changes in Prices and Production Costs Related to Future Production 3,302 142 (1,249) -------------------------------------------------------------------------------------------------------------------- Extensions, Discoveries and Improved Recovery, Less Related Costs (1) 977 (71) 740 -------------------------------------------------------------------------------------------------------------------- Changes in Estimated Future Development and Dismantlement Costs (135) (122) (279) -------------------------------------------------------------------------------------------------------------------- Previous Estimated Future Development and Dismantlement Costs Incurred During the Period 638 604 456 -------------------------------------------------------------------------------------------------------------------- Revisions of Previous Quantity Estimates 478 (223) (291) -------------------------------------------------------------------------------------------------------------------- Accretion of Discount 799 692 884 -------------------------------------------------------------------------------------------------------------------- Purchases of Reserves in Place 15 1,764 354 -------------------------------------------------------------------------------------------------------------------- Sales of Reserves in Place (882) (20) (252) -------------------------------------------------------------------------------------------------------------------- Net Change in Income Taxes (1,412) (319) 1,083 -------------------------------------------------------------------------------------------------------------------- End of Year 8,042 6,290 5,517 --------------------------------------------------------------------------------------------------------------------
Note: (1) 2004 includes approximately $230 million of negative discounted future net cash flows relating to bitumen reserves based on year-end assumptions. 121 EXHIBITS 23.1* Consent of Independent Registered Chartered Accountants 23.2* Consent of William M. Cobb & Associates, Inc. 23.3* Consent of Ryder Scott Company, L.P. 23.4* Consent of McDaniel & Associates Consultants Ltd. 23.5* Consent of DeGolyer and MacNaughton. 31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1* Certification of periodic report by Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2* Certification of periodic report by Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Filed herewith. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on April 2, 2007. NEXEN INC. By: /s/ Charles W. Fischer ---------------------------- Charles W. Fischer President, Chief Executive Officer and Director (Principal Executive Officer)